SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
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| ý | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 20102013 ¨ |
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| o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File Number: 1-8182
PIONEER
DRILLING COMPANYENERGY SERVICES CORP.
(Exact name of registrant as specified in its charter)
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| TEXAS | | 74-2088619 |
(State or other jurisdiction of incorporation or organization)
| | Identification Number)
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1250 N.E. Loop 410, Suite 1000 San Antonio, Texas
| | 78209 |
| (Address of principal executive offices) | | (Zip Code) |
Registrant’s telephone number, including area code:
(210) 828-7689(855) 884-0575
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class | | Name of each exchange on which registered |
| Common Stock, $0.10 par value | | NYSE Amex |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨No þ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þNo ¨ Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨ No ¨ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer ¨o | | | | Accelerated filer þ |
Non-accelerated filer ¨o | | (Do not check if a smaller reporting company) | | Smaller reporting company ¨o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ The aggregate market value of the registrant’s common stock held by nonaffiliates of the registrant onas of the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing sales price on the AmericanNew York Stock Exchange (NYSE Amex)(NYSE) on June 30, 2010)2013) was approximately $303.8 million.$406.8 million. As of February 4, 2011,January 30, 2014, there were 54,243,45262,537,694 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding. DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement related to the registrant’s 20112014 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about our company. These statements may include projections and estimates concerning the timing and success of specific projects and our future backlog, revenues, income and capital spending. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “plan,” “intend,” “seek,” “will,” “should,” “goal” or other words that convey the uncertainty of future events or outcomes. These forward-looking statements speak only as of the date on which they are first made, which in the case of forward-looking statements made in this report is the date of this report. Sometimes we will specifically describe a statement as being a forward-looking statement and refer to this cautionary statement.
In addition, various statements contained in this Annual Report on Form 10-K, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. Such forward-looking statements appear in Item 1—“Business” and Item 3—“Legal Proceedings” in Part I of this report; in Item 5—“Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities,” Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Item 7A—“Quantitative and Qualitative Disclosures About Market Risk” and in the Notes to Consolidated Financial Statements we have included in Item 8 of Part II of this report; and elsewhere in this report. These forward-looking statements speak only as of the date of this report. We disclaim any obligation to update these statements, and we caution you not to
relyplace undue reliance on
them unduly.them. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:
general economic and business conditions and industry trends;
levels and volatility of oil and gas prices;
decisions about onshore exploration and development projects to be made by oil and gas exploration and production companies;
economic cycles and their impact on capital markets and liquidity;
the continued demand for drilling services or production services in the geographic areas where we operate;
the highly competitive nature of our business;
our future financial performance, including availability, terms and deployment of capital;
future compliance with covenants under our senior secured revolving credit facility and our senior notes;
the supply of marketable drilling rigs, well serviceservicing rigs, coiled tubing and wireline units within the industry;
changes in technology and improvements in our competitors' equipment;
the continued availability of drilling rig, well serviceservicing rig, coiled tubing and wireline unit components;
the continued availability of qualified personnel;
the success or failure of our acquisition strategy, including our ability to finance acquisitions, manage growth and manage growth;effectively integrate acquisitions; and
changes in, or our failure or inability to comply with, governmental regulations, including those relating to the environment.
We believe the items we have outlined above are important factors that could cause our actual results to differ materially from those expressed in a forward-looking statement contained in this report or elsewhere. We
have discussed many of these factors in more detail elsewhere in this report. UnpredictableOther unpredictable or unknown factors we have not discussed in this report could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements.
We
do not intendundertake no duty to update
our description of important factors each time a potential important factor arises,or revise any forward-looking statements, except as required by applicable securities laws and regulations. We advise our security holders that they should (1) be aware that unpredictable or unknown factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements. Also, please read the risk factors set forth in Item 1A—“Risk Factors.”
General
GeneralPioneer Energy Services (formerly called "Pioneer Drilling CompanyCompany") was incorporated under the laws of the State of Texas in 1979 as the successor to a business that had been operating since 1968. Since September 1999, we have significantly expanded our drilling rig fleet through acquisitions and through the construction of rigs from new and used components. In March 2008, we acquired two production services companies which significantly expanded our service offerings to include well servicing, wireline services and fishing and rental services. We have continued to invest in the growth of all our service offerings through acquisitions and organic growth. On December 31, 2011, we acquired the coiled tubing services business of Go-Coil, L.L.C. ("Go-Coil") to expand our existing production services offerings.
In 2012, we changed our company name from "Pioneer Drilling Company" to "Pioneer Energy Services Corp." Our common stock trades on the New York Stock Exchange under the ticker symbol "PES." Our new name reflects our strategy to expand our service offerings beyond drilling services, which has been our core, legacy business.Pioneer Energy Services provides drilling services and production services to a diverse group of independent and majorlarge oil and gas exploration and production companies throughout much of the onshore oil and gas producing regions of the United States and internationally in Colombia. Pioneer Drilling Company was incorporated under the laws of the State of Texas in 1979 as the successor to a business that had been operating since 1968. Our business has grown through acquisitionsWe also provide coiled tubing and through organic growth. Since September 1999, we have significantly expanded our drilling rig fleet by adding 35 rigs through acquisitions and by adding 31 rigs through the construction of rigs from new and used components. We significantly expanded our service offerings in March 2008, when we acquired the production services businesses of WEDGE Group Incorporated (“WEDGE”) for $314.7 million and Prairie Investors d/b/a Competition Wireline (“Competition”) for $30.0 million, which provide well services, wireline services and fishing and rental services. We fundedoffshore in the WEDGE acquisition primarily with $311.5 millionGulf of borrowings under our senior secured revolving credit facility.Mexico. Drilling services and production services are fundamental to establishing and maintaining the flow of oil and natural gas throughout the productive life of a well site and enable us to meet multiple needs of our customers.clients.
We currently conduct our operations through two operating segments: our Drilling Services DivisionSegment and our Production Services Division.Segment. The following is a description of these two operating segments. Financial information about our operating segments is included in Note 11, Segment Information, of the Notes to Consolidated Financial Statements, included in Part II, Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.10-K | • | | Drilling Services Division—Our Drilling Services Division provides contract land drilling services with its fleet of 71 drilling rigs in the following locations:
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. Drilling Services Segment—Our Drilling Services Segment provides contract land drilling services to a diverse group of oil and gas exploration and production companies with its fleet of 62 drilling rigs which are currently assigned to the following divisions:
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Drilling Division Locations | | Rig Count | |
South Texas | | 14 | 19 |
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EastWest Texas
| | 18 | 13 |
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West Texas
North Dakota | | 11 | 3 |
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North Dakota
| | | 9 | |
North Texas
| | | 3 | |
Utah | | | 3 | |
Oklahoma
| | | 6 | |
Appalachia
| | | 7 |
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Colombia
Appalachia | | 4 |
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| Colombia | | 8 |
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| | 62 |
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As
In early 2011, we began construction of February 4, 2011, 48 drilling rigs are operating under drilling contracts. We have 17ten new-build AC drilling rigs that are idle and sixfit for purpose for domestic shale plays, based on term contracts. We deployed seven of these new-build drilling rigs have been placedduring 2012, and deployed the final three in storage or “cold stacked” inearly 2013. All of our Oklahoma drilling division location due to low demand fornew-build drilling rigs are currently operating in that region. We are actively marketing all our idleshale or unconventional plays under long-term drilling rigs. contracts.
During the second quarter of 2009,2013, we established our Appalachia drilling division location and now have seven drilling rigs operating in the Marcellus Shale. In early 2011, weestablished our West Texas drilling division location with threesold
two mechanical drilling rigs that were previously includedidle in our East Texas division, for which we recognized an associated gain of approximately $0.8 million. In September 2013, we decided to sell eight of our mechanical drilling division location. Onerigs, for which we recognized an impairment charge of $9.2 million dollars during the third quarter. All eight drilling rigs were classified as held for sale at September 30, 2013 and were sold in late October 2013. We did not incur any additional gain or loss upon the sale of these rigs. As of December 31, 2013, 50 of our 62 drilling rigs has begunare earning revenues under drilling in the Permian Basincontracts, 39 of which are under term contracts, and we are actively marketing all of our idle drilling rigs. All eight of our drilling rigs in Colombia are currently under term contracts that extend through the end of 2014, seven of which are currently working. The remaining rig will begin working under its term contract after it is upgraded from 1,000 horsepower to 1,500 horsepower, which we expect will be completed by the remaining two rigs to begin operations in late February 2011. end of the first quarter of 2014.
In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with
customers.existing or potential clients. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, and the anticipated duration of the work to be performed.
| • | | Production Services Division—Our Production Services DivisionProduction Services Segment—Our Production Services Segment provides a range of services to oil and gas exploration and production companies, including well services, wireline services, and fishing and rental services. Our production services operations are managed through locations concentrated in the major United States onshore oil and gas producing regions in the Gulf Coast, Mid-Continent, Rocky Mountain and Appalachian states. We provide our services to a diverse group of oil and gas exploration and production companies. The primary production services we offer are the following:
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Well Services. Existing and newly-drilled wells require a range of services to exploration and production companies, including well servicing, wireline services, coiled tubing services, and fishing and rental services. Our production services operations are concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore. We provide our services to a diverse group of oil and gas exploration and production companies. The primary production services we offer are the following:
Well Servicing. A range of services are required in order to establish production in newly-drilled wells and to maintain production over theirthe useful lives.lives of active wells. We use our premium well serviceservicing rig fleet to provide these requirednecessary services, including the completion of newly-drilled wells, maintenance of existing wells,and workover of existing wells, completion of newly-drilledactive wells, and plugging and abandonment of wells at the end of their useful lives. We acquired one well service rig in early 2011, resulting in a total As of 75 well service rigs in nine locations as of February 4, 2011. Our well service rig fleet consists of seventyDecember 31, 2013, we operate ninety-nine 550 horsepower rigs fourand ten 600 horsepower rigs through 11 locations, mostly in the Gulf Coast and one 400 horsepower rig, with an average age of 3.4 years. All our well serviceArkLaTex regions, though we also have 14 rigs are currently operating or are being actively marketed, with January 2011 utilization of approximately 88%. We plan to add another five well service rigs to our fleet by mid-2011.in North Dakota.
Wireline Services. In order for oil and gas exploration and production companies to better understand the reservoirs they are drilling or producing, they require logging services to accurately characterize reservoir rocks and fluids. WhenTo complete a producing well, is completed, they also must perforate the production casing must be perforated to establish a flow path between the reservoir and the wellbore. We use our fleet of wireline units to provide these important logging and perforating services. We provide both open and cased-hole logging services, including the latest pulsed-neutron technology. In addition, we provide services which allow oil and gas exploration and production companies to evaluate the integrity of wellbore casing, recover pipe, or install bridge plugs. We acquired 21 As of December 31, 2013, we operate through 24 locations with a fleet of 119 wireline units.
Coiled Tubing Services. Coiled tubing is an important element of the well servicing industry that allows operators to continue production during service operations without shutting in the well, thereby reducing the risk of formation damage. Coiled tubing services involve the use of a continuous metal pipe spooled on a large reel for oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, formation stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is also used for a number of horizontal well applications such as milling temporary plugs between frac stages. As of December 31, 2013, our coiled tubing business consists of nine onshore and four offshore coiled tubing units during 2010which are currently deployed through three locations in Texas and two additional wireline units in early 2011, resulting in a total of 86 wireline units in 22 locations as of February 4, 2011. We plan to add another 12 wireline units by mid-2011.Louisiana.
Fishing and Rental Services. During drilling operations, oil and gas exploration and production companies frequently rent unique equipment such as power swivels, foam circulating units, blow-out preventers, air drilling equipment, pumps, tanks, pipe, tubing and fishing tools. We provide rental services out of fourthree locations in Texas and Oklahoma. As of December 31, 20102013 our fishing and rental tools have a gross book value of $13.5 million.$17.3 million.
Pioneer Drilling Company’sEnergy Services' corporate office is located at 1250 N.E.NE Loop 410, Suite 1000, San Antonio, Texas 78209. Our phone number is (210) 828-7689(855) 884-0575 and our website address iswww.pioneerdrlg.com. www.pioneeres.com. We make available free of charge though our website our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with the Securities and Exchange Commission (the “SEC”)(SEC). Information on our website is not incorporated into this report or otherwise made part of this report.
Demand for oilfield services offered by our industry is a function of our customers’clients’ willingness to make operating expenditures and capital expenditures to explore for, develop and produce hydrocarbons, which in turn is affected by current and expected levels of oil and natural gas prices. From 2004 through 2008, domestic exploration and production spending increased as oil and natural gas prices increased. Since late 2008 and into late 2009, there has beenwas substantial volatility and a decline in oil and natural gas prices due to the downturn in the global economic environment. In response, our customersclients curtailed their drilling programs and reduced their production activities, particularly in natural gas producing regions, which resulted in a decrease in demand and revenue rates for certain of our drilling rigs and production services equipment. Additionally, there was uncertainty in the capital markets and access to financing was limited. These conditions adversely affected our business environment. For additional information concerning the effects of the volatility in oil and gas prices and uncertainty in capital markets, see Item 1A—“Risk Factors” in Part I of this Annual Report on Form 10-K. With generally increasing oil prices in 2010 and natural gas prices through 2010,2011, exploration and production companies modestly increased their exploration and production spending for 2010 and industry rigequipment utilization and revenue rates improved, particularly in oil-producing regions and in certain shale regions. We expect continuedDuring 2012, modest increases in exploration and production spending for 2011, which we expect will resultresulted in modest increases in industry rigequipment utilization and revenue rates in 2011,during 2012, as compared to 2010.On February 4, 2011,2011. Despite generally increasing oil prices during 2013, industry equipment utilization levels have been slightly lower than industry levels during 2012, which is partially due to the spot price foradvancements in technology and efficiency of drilling rigs. In addition, excess natural gas production in the U.S. shale regions continues to depress natural gas prices. If oil and natural gas prices decline, then industry equipment utilization and revenue rates could decrease domestically and in Colombia.
Colombia has experienced significant growth in oil production since 2008 largely due to the infusion of capital by international exploration and production companies as a result of the country's improved regulation and security. Historically, Colombian oil prices have generally trended in line with West Texas Intermediate crude(WTI) oil was $89.03,prices. However, fluctuations in oil prices have a less significant impact on demand for drilling and production services in Colombia as compared to the spot priceimpact on demand in North America. Demand for Henry Hub natural gas was $4.47drilling and production services in Colombia is largely dependent upon the Baker Hughes land rig count was 1,696, a 33% increase from 1,280 on February 5, 2010. national oil company's long-term exploration and production programs.
The
average weeklytrends in spot prices of
West Texas IntermediateWTI crude oil and Henry Hub natural gas,
and the
average weeklyresulting trends in domestic land rig
count per thecounts (per Baker
Hughes land rig count,Hughes) and
the average monthly domestic well
serviceservicing rig
count for eachcounts (per Guiberson/Association of
Energy Service Companies) over the last five years
were: | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | | | 2007 | | | 2006 | |
Oil (West Texas Intermediate) | | $ | 79.39 | | | $ | 61.81 | | | $ | 99.86 | | | $ | 72.71 | | | $ | 66.28 | |
Natural Gas (Henry Hub) | | $ | 4.35 | | | $ | 3.85 | | | $ | 8.81 | | | $ | 6.90 | | | $ | 6.66 | |
U.S. Land Rig Count | | | 1,493 | | | | 1,035 | | | | 1,792 | | | | 1,670 | | | | 1,537 | |
U.S. Well Service Rig Count | | | 1,854 | | | | 1,735 | | | | 2,514 | | | | 2,388 | | | | 2,364 | |
As representedare illustrated in the tablegraphs below.
As shown in the charts above, increasesthe trends in industry rig counts are influenced by fluctuations in oil and natural gas prices, from 2004 to late 2008 resulted in corresponding increases inwhich affect the U.S. land rig countslevels of capital and U.S. well service rig counts, while declines in prices from late 2008 to late 2009 led to decreases in the U.S. land rig counts and U.S. well service rig counts. Since late 2009, increases in oil and natural gas prices have caused modest increases in exploration and production spending and the corresponding increases in drilling and well services activities is reflectedoperating expenditures made by increases in the U.S. land rig counts and the U.S. well service rig counts in 2010.our clients.
Our business is influenced substantially by both operating and capital expenditures by exploration and production companies. Exploration and production spending is generally categorized as either a capital expenditure or operating expenditure. Capital expenditures by oil and gas exploration and production companies tend to be relatively sensitive to volatility in oil or natural gas prices because project decisions are tied to a return on investment spanning a number of years. As such, capital expenditure economics often require the use of commodity price forecasts which may prove inaccurate in the amount of time required to plan and execute a capital expenditure project (such as the drilling of a deep well). When commodity prices are depressed for long periods of time, capital expenditure projects are routinely deferred until prices return to an acceptable level. In contrast, both mandatory and discretionary operating expenditures are more stable than capital expenditures for exploration.exploration as these expenditures are less sensitive to commodity price volatility. Mandatory operating expenditure projects involve activities that cannot be avoided in the short term, such as regulatory compliance, safety, contractual obligations and certain projects to maintain the well and related infrastructure in operating condition. Discretionary operating expenditure projects may not be critical to the short-term viability of a lease or field but these projectsand are less sensitive to commodity price volatility as compared to capital expenditures for exploration. Discretionary operating expenditure work isgenerally evaluated according to a simple short-term payout criterion whichthat is far less dependent on commodity price forecasts.forecasts
. Because existing oil and natural gas wells require ongoing spending to maintain production, expenditures by exploration and production companies for the maintenance of existing wells are relatively stable and predictable. In contrast, capital expenditures by exploration and production companies for exploration and drilling are more directly influenced by current and expected oil and natural gas prices and generally reflect the volatility of commodity prices. Technological advancements and trends in our industry also affect the demand for certain types of equipment. During 2013, the demand for traditional drilling rigs in vertical markets has softened due to increased demand for drilling rigs that are able to drill horizontally. In addition, oil and gas exploration and production companies have increased the use of "pad drilling" in recent years whereby a series of horizontal wells are drilled in succession by a walking or skidding drilling rig at a single pad-site location. Pad drilling has improved the productivity of exploration and production activities which could reduce the demand for drilling rigs, particularly those that do not have the ability to walk or skid and to drill horizontal wells.
For additional information concerning the effects of the volatility in oil and gas prices and the effects of technological advancements and trends, see Item 1A – “Risk Factors” in Part I of this Annual Report on Form 10-K.
Our competitive strengths include:
| • | | One of the Leading Providers in the Most Attractive Basins.Our 71 drilling rigs operate in many of the most attractive producing basins in the Americas, including the Bakken, Marcellus and Eagle Ford shales, as well as Colombia. Our rigs are located in nine divisions throughout the United States and Colombia, diversifying our geographic exposure and limiting the impact of any regional slowdown. We believe the varied capabilities of our rigs make them well suited to these areas where the optimal rig configuration is dictated by local geology and market conditions. Furthermore, certain of our division locations, such as Colombia, North Dakota, West Texas and parts of our South Texas division location, are in basins with oil-focused drilling, which reduces our relative exposure to changes in natural gas drilling activity.
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| • | | High Quality Assets.We believe our drilling rig fleet is modern and well maintained, with 31 new-build rigs purchased since 2001, and the majority of these constructed from 2004 to 2006. The majority of our rig fleet has preferred equipment such as more efficient and lower emission engines, rounded bottom mud tanks, matched horsepower mud pumps and mobile or fast-paced substructures. In addition, 69% of our rig fleet has a horsepower rating of 1000 to 2000 horsepower and 49% has top drives, which allows us to pursue opportunities in shale plays, which typically require higher specification rigs than traditional areas. Our wireline and well servicing assets are among the newest in the industry, with 54% having been built in 2007 or later, and all but one of the well service rigs having at least 550 horsepower. We expect to add a total of 13 wireline units and six well service rigs during the first half of 2011. We believe that our modern and well maintained fleet allows us to realize higher contract and utilization rates by being able to offer our customers equipment that is more reliable and requires less downtime than older equipment.
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| • | | Provide Services Throughout the Well Life Cycle. By offering our customers drilling, production and related services, we capture revenue throughout the life cycle of a well and diversify our business. Our Drilling Services Division performs work prior to initial production, and our Production Services Division provides services such as logging, completion, perforation, workover and maintenance throughout the productive life of a well. We also provide certain end-of-well-life activities such as plugging and abandonment. Drilling and production services activity have historically exhibited different degrees of demand fluctuation, and we believe the diversity of our services reduces our exposure to decreases in demand for any single service activity. The diversity of our services also enhances customer revenues by allowing us to cross-sell services in our various business divisions.
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| • | | Excellent Safety Record.We believe that our excellent safety record and reputation are critical to winning new business and expanding our relationships with existing customers. Our commitment to
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| safety also reduces our business risk by keeping our employees safe and our equipment in good condition. We have consistently exceeded the International Association of Drilling Contractors (IADC) average for recordable incidents and have achieved a 70% improvement in recordable incidents since 2005. Much of our equipment contains additional safety features such as the iron roughnecks we have installed on 63% of our drilling rigs. We received scores of 100% on several health, safety and environment audits conducted during 2009 and 2010 by Ecopetrol S.A. (NYSE: EC), one of the leading oil companies in Latin America, for whom we currently operate eight drilling rigs in Colombia. We believe our strong performance on such measures has contributed significantly to our growing business with Ecopetrol.
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| • | | Experienced Management Team.We believe that important competitive factors in establishing and maintaining long-term customer relationships include having an experienced and skilled management team and maintaining employee continuity. Our CEO, Wm. Stacy Locke, joined Pioneer in 1995 as President and has over 25 years of industry experience. Our two division presidents, F.C. “Red” West and Joe Eustace, have over 70 years of combined oilfield services experience. Our management team has operated through numerous oilfield services cycles and provides us with valuable long-term experience and a detailed understanding of customer requirements. We also seek to maximize employee continuity and minimize employee turnover by maintaining modern equipment, a strong safety record, ongoing growth and competitive compensation. We have devoted, and will continue to devote, substantial resources to our employee safety and training programs and maintaining low employee turnover.
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| • | | Longstanding and Diversified Customers.We maintain long-standing, high quality customer relationships with a diverse group of major independent oil and gas exploration and production companies including Anadarko Petroleum Corporation, Cabot Oil and Gas Corporation, Whiting Petroleum Corporation and Chesapeake Energy Corporation. We also maintain a high quality relationship with Ecopetrol, which accounted for approximately 17.8% of our 2010 consolidated revenues. No other single customer accounted for more than 8.9% of consolidated revenues during the same period. We believe our relationships with our customers are excellent and offer numerous opportunities for future growth.
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One of the Leading Providers in the Most Attractive Regions. Our 62 drilling rigs operate in many of the most attractive producing regions in the Americas, including the Bakken, Marcellus and Eagle Ford shales, and Permian and Uintah Basins, as well as Colombia. Our drilling rigs are located in six divisions throughout the United States and Colombia, diversifying our geographic exposure and limiting the impact of any regional slowdown. We believe the varied capabilities of our drilling rigs make them well suited to these areas where the optimal rig configuration is dictated by local geology and market conditions.
High Quality Assets. We have purchased 40 new-build drilling rigs since 2001, ten of which are new-build AC drilling rigs which we constructed during 2011 to 2013. Approximately 74% of our drilling rigs are capable of drilling horizontal wells and the majority of these rigs are also equipped with either a walking or skidding system for pad drilling. Approximately 74% of our production services assets have been built since 2007, and all of our well servicing rigs have at least 550 horsepower. We believe that our modern and well maintained fleet allows us to realize higher contract and utilization rates because we are able to offer our clients equipment that is more reliable and requires less downtime than older equipment.
Provide Services Throughout the Well Life Cycle. By offering our clients both drilling and production services, we capture revenue throughout the life cycle of a well and diversify our business. Our Drilling Services Segment performs work prior to initial production, and our Production Services Segment provides services such as logging, completion, perforation, workover and maintenance throughout the productive life of a well. We also provide certain end-of-well-life activities such as plugging and abandonment. Drilling and production services activity have historically exhibited different degrees of demand fluctuation, and we believe the diversity of our services reduces our exposure to decreases in demand for any single service activity. Further, the diversity of our service offerings enables us to cross-sell our services, benefiting our clients, allowing us to generate more business from existing clients and increasing our profits as we expand our services within existing markets.
Excellent Safety Record. Our safety program called “LiveSafe” focuses on creating an environment where everyone is committed to and recognizes the possibility of always working without incident or injury. We believe that by building strong relationships among our people we can achieve an excellent safety record. Our excellent safety record and reputation are critical to winning new business and expanding our relationships with existing clients. Our commitment to safety helps us to keep our employees safe and reduces our business risk.
Experienced Management Team. We believe that important competitive factors in establishing and maintaining long-term client relationships include having an experienced and skilled management team and maintaining employee continuity. Our CEO, Wm. Stacy Locke, joined Pioneer in 1995 as President and has 35 years of industry experience. Our two segment presidents, F.C. “Red” West and Joe Eustace, have 85 years of combined oilfield services experience. Our management team has operated through numerous oilfield services cycles and provides us with valuable long-term experience and a detailed understanding of client requirements. We also seek to maximize employee continuity and minimize employee turnover by maintaining modern equipment, a strong safety record, ongoing growth and competitive compensation. We have devoted, and will continue to devote, substantial resources to our employee safety and training programs and maintaining low employee turnover.
Longstanding and Diversified Clients. We maintain long-standing, high quality client relationships with a diverse group of large independent oil and gas exploration and production companies including Whiting Petroleum Corporation, which accounted for approximately 13% of our 2013 consolidated revenues, Apache Corporation, Hess Corporation, Pioneer Natural Resources and Continental Resources. We also maintain a good relationship with Ecopetrol, which accounted for approximately
11% of our 2013 consolidated revenues. We believe our relationships with our clients are excellent and offer numerous opportunities for future growth.
In past years, our strategy was to become a premier land drilling and production services company through steady and disciplined growth. We executed this strategy by acquiring and building a high quality drilling rig fleet and production services business
thatwhich we operate in
activethe most attractive drilling markets
inthroughout the United States and
in Colombia. Our long-term strategy is to maintain and leverage our position as a leading land drilling and production services company, continue to expand our relationships with existing
customers,clients, expand our
customerclient base in the areas
in whichwhere we currently operate and further enhance our geographic diversification through selective
international expansion. The key elements of this long-term strategy
include: | • | | Further Strengthen our Competitive Position in the Most Attractive Domestic Markets.Shale plays are expected to become increasingly important to domestic hydrocarbon production in the coming years and not all drilling rigs are capable of successfully drilling in these shale play opportunities. We currently have 39 drilling rigs capable of operating in unconventional plays. Of these 39 drilling rigs, 30 are currently operating in unconventional plays, eight are currently operating in Colombia under term contracts and one is operating domestically on a conventional well. We have 21 other drilling rigs that would require additional upgrades such as top drives to be capable of operating in unconventional plays. We may consider further upgrades in the future if they will result in profitable contract terms that justify the additional investment. We also intend to continue adding capacity to our wireline and well servicing product offerings, which are well positioned to capitalize on increased shale development.
|
| • | | Increase our Exposure to Oil-Driven Drilling Activity.We have intentionally increased our exposure to oil-related activities by redeploying certain of our assets into predominately oil-producing regions and actively seeking contracts with oil-focused producers. Currently, 60% of both our working drilling rigs and our well service rigs are operating on wells that are targeting or producing oil. In addition, we currently have one rig drilling in the Permian Basin, an oil producing region, and expect to have another two drilling rigs operating in this area by the end of February 2011. We believe that by targeting a balanced mix of oil and natural gas activities, we can lessen our exposure to fluctuations in capital spending associated with changes in any single commodity price. We believe that our flexible rig fleet and production services assets allow us to target opportunities focused on both natural gas and oil.
|
| • | | Selectively Expand our International Operations. In early 2007, we announced our intention to selectively expand internationally and began a relationship with Ecopetrol S.A. in Colombia after a comprehensive review of international opportunities wherein we determined that Colombia offered an attractive mix of favorable business conditions, political stability, and a long-term commitment to expanding national oil and gas production. We now have eight drilling rigs operating under term drilling contracts in Colombia. We are continuously evaluating additional international expansion opportunities and intend to target international markets that share the favorable characteristics of our Colombian operations and which would allow us to deploy sufficient assets in order to realize economies of scale.
|
| • | | Continue Growth with Select Capital Deployment. We intend to invest in the growth of our business by continuing to strategically upgrade our existing assets, selectively engaging in new-build opportunities, and potentially making selective acquisitions. Our capital investment decisions are determined by an analysis of the projected return on capital employed, which is based on the terms of secured contracts whenever possible, and the investment must be consistent with our strategic objectives. For example, we began our operations in Colombia in 2007 to diversify our operations into the international market, and we established our Appalachia drilling division location in 2009 to supply drilling rigs to the rapidly growing demand in the Marcellus Shale. We continued investing in these opportunities during 2010, exporting an additional two rigs to Colombia and placing an additional four rigs in the Appalachia drilling division location, all of which were equipped with upgrades such as top drives and walking/skidding systems. We now have a total of 15 drilling rigs in these locations as of February 4, 2011. We also significantly increased our production services wireline fleet with the addition of 21 wireline units during 2010, and we expect to add a total of 14 wireline units and six well service rigs during the first half of 2011.
|
are focused on our:
Competitive Position in the Most Attractive Domestic Markets. Shale plays and non-shale oil or liquid rich environments are increasingly important to domestic hydrocarbon production and not all drilling rigs are capable of successfully drilling in these unconventional opportunities. We are currently operating in unconventional areas in the Bakken, Marcellus and Eagle Ford shales and Permian and Uintah Basins. All of the ten drilling rigs we recently constructed are currently operating in domestic shale and unconventional plays. Additionally, in recent years, we have added significant capacity to our production services fleets, which we believe are well positioned to capitalize on increased shale development.
Exposure to Oil and Liquids Rich Natural Gas Drilling Activity. We believe that our flexible drilling and production services fleets allow us to pursue varied opportunities, enabling us to focus on a favorable mix of natural gas, oil and liquids rich natural gas activity. In recent years, we have intentionally increased our exposure to oil-related activities by redeploying certain of our assets into predominately oil-producing regions and we continue to actively seek contracts with oil-focused producers. As of December 31, 2013, approximately 92% of our working drilling rigs and 78% of our production services assets are operating on wells that are targeting or producing oil or liquids rich natural gas.
International Presence. In 2007, we began operating in Colombia after a comprehensive review of international opportunities wherein we determined that Colombia offered an attractive mix of favorable business conditions, political stability, and a long-term commitment to expanding national oil and gas production. All eight of our drilling rigs in Colombia are currently under term contracts that extend through the end of 2014, seven of which are currently working, while the remaining rig will begin working under its term contract after certain upgrades are completed during the first quarter of 2014.
Growth Through Select Capital Deployment. We have historically invested in the growth of our business by strategically upgrading our existing assets, selectively engaging in new-build opportunities, and through selective acquisitions. We have continued to make significant investments in the growth of our business over the past several years. For example, on December 31, 2011, we acquired a coiled tubing services business to expand our existing production services offerings. We have also added significant capacity to our other production services fleets through the addition of 56 wireline units and 35 well servicing rigs since the beginning of 2010. In 2011, we began construction, based on term contracts, of ten new-build AC drilling rigs, all of which are currently operating in domestic shale or unconventional plays.
With these capital projects recently completed, we have shifted our near-term focus toward reducing capital expenditures and using excess cash flows from operations to reduce outstanding debt balances and reposition ourselves for future long-term growth. Management efforts are currently focused on stringent cost control measures, the evaluation of nonstrategic or under-performing assets for potential liquidation and continued emphasis on the execution and performance of our core businesses. We believe this near-term strategy will position us to take advantage of future business opportunities and continue our long-term growth strategy.
Overview of Our Segments and Services
Drilling Services
DivisionSegment
There are numerous factors that differentiate land drilling rigs, including their power generation systems and their drilling depth capabilities. A land drilling rig consists of engines, a hoisting system, a rotating system, pumps and related equipment to circulate drilling fluid, blowout preventers and related equipment.
Generally, drilling rigs operate with crews of five to six persons.
Diesel or gas engines are typically the main power sources for a drilling rig. Power requirements for drilling jobs may vary considerably, but most land drilling rigs employ two or more engines to generate between 500 and 2,000 horsepower, depending on well depth and rig design. Most drilling rigs capable of drilling in deep formations, involving depths greater than 15,000 feet, use diesel-electric power units to generate and deliver electric current through cables to electrical switch gears, then to direct-current electric motors attached to the equipment in the hoisting, rotating and circulating systems.
Drilling rigs use long strings of drill pipe and drill collars to drill wells. Drilling rigs are also used to set heavy strings of large-diameter pipe, or casing, inside the borehole. Because the total weight of the drill string and the casing can exceed 500,000 pounds, drilling rigs require significant hoisting and braking capacities.
Generally, a drilling rig’s hoisting system is made up of a mast, or derrick, a traveling block and hook assembly that attaches to the rotating system, a mechanism known as the drawworks, a drilling line and ancillary equipment. The drawworks mechanism consists of a revolving drum, around which the drilling line is wound, and a series of shafts, clutches and chain and gear drives for generating speed changes and reverse motion. The drawworks also houses the main brake, which has the capacity to stop and sustain the weights used in the drilling process. When heavy loads are being lowered, a hydraulic or electric auxiliary brake assists the main brake to absorb the great amount of energy developed by the mass of the traveling block, hook assembly, drill pipe, drill collars and drill bit or casing being lowered into the well.
The rotating equipment from top to bottom consists of a top drive or a swivel, the kelly, and kelly bushing, the rotary table, drill pipe, drill collars and the drill bit. We refer to the equipment between the top drive or swivel and the drill bit as the drill stem. In a top drive system, the top drive hangs from a hook at the bottom of the traveling block. The top drive has a passageway for drilling mud to get into the drill pipe, and it has a heavy-duty electric motor connected to a threaded drive shaft which connects to and rotates the drill pipe. In a kelly drive system, the swivel assembly sustains the weight of the drill stem, permits its rotation and affords a rotating pressure seal and passageway for circulating drilling fluid into the top of the drill string. The swivel also has a large handle that fits inside the hook assembly at the bottom of the traveling block. Drilling fluid enters the drill stem through a hose, called the rotary hose, attached to the side of the swivel. The kelly is a triangular, square or hexagonal piece of pipe, usually 40 feet long, that transmits torque from the rotary table to the drill stem and permits its vertical movement as it is lowered into the hole. The bottom end of the kelly fits inside a corresponding triangular, square or hexagonal opening in a device called the kelly bushing. The kelly bushing, in turn, fits into a part of the rotary table called the master bushing. As the master bushing rotates, the kelly bushing also rotates, turning the kelly, which rotates the drill pipe and thus the drill bit. Drilling fluid is pumped through the kelly on its way to the bottom. The rotary table, equipped with its master bushing and kelly bushing, supplies the necessary torque to turn the drill stem. The drill pipe and drill collars are both steel tubes through which drilling fluid can be pumped. Drill pipe, sometimes called drill string, comes in 30-foot sections, or joints, with threaded sections on each end. Drill collars are heavier than drill pipe and
both are
also threaded on the ends. Collars are used on the bottom of the drill stem to apply weight to the drilling bit. At the end of the drill stem is the bit, which chews up the formation rock and dislodges it so that drilling fluid can circulate the fragmented material back up to the surface where the circulating system filters it out of the fluid.
Drilling fluid, often called mud, is a mixture of clays, chemicals and water or oil, which is carefully formulated for the particular well being drilled. Drilling mud accounts for a major portion of the cost incurred and equipment used in drilling a well. Bulk storage of drilling fluid materials, the pumps and the mud-mixing equipment are placed at the start of the circulating system. Working mud pits and reserve storage are at the other end of the system. Between these two points, the circulating system includes auxiliary equipment for drilling fluid maintenance and equipment for well pressure control. Within the system, the drilling mud is typically routed from the mud pits to the mud pump and from the mud pump through a standpipe and the rotary hose to the drill stem. The drilling mud travels down the drill stem to the bit, up the annular space between the drill stem and the borehole and through the blowout preventer stack to the return flow line. It then travels to a shale shaker for removal of rock cuttings, and then back to the mud
pits, which are usually steel tanks. The reserve pits, usually one or two fairly shallow excavations, are used for waste material and excess water around the location.
In a continuing effort
Drilling rigs use long strings of drill pipe and drill collars to
improve our drilling rig fleet, we have installed top drives in 35drill wells. Drilling rigs
(with four additional spare top drives available for installation), iron roughnecks in 45 rigs, walking/skidding systems in 13 rigs (with three additional walking/skidding systems available for installation)are also used to set heavy strings of large-diameter pipe, or casing, inside the borehole. Because the total weight of the drill string and
automatic catwalks in eight rigs. These upgrades provide our customers withthe casing can exceed 500,000 pounds, drilling rigs
that have more varied capabilities for drilling in unconventional plays,require significant hoisting and
they improve our efficiency and safety. Top drives provide maximum torque and rotational control, improved well control and better hole conditioning. In horizontal drilling, operators can utilize top drives to reach formations that may not be accessible with conventional rotary drilling. An iron roughneck is a remotely operated pipe handling feature on the rig floor, which is used to help reduce the occurrence of repetitive motion injuries and decrease drill pipe tripping time. Walking systems increase efficiency by allowingmultiple wells to be drilled on the same pad site and permitting the drilling rig to move between wells while drill pipe remains in the derrick, thus reducing move times and costs. Our walking system enables the drilling rig to move forward, backward, and side to side which affords the operator additional flexibility. An automated catwalk is a drill pipe handling feature used to raise drill pipe, drill collars, casing, and other necessary items to the drilling rig floor. Its function drastically reduces pick up and lay down time, thereby decreasing operator costs for handling casing.
There are numerous factors that differentiate land drilling rigs, including their power generation systems and their drilling depth capabilities.braking capacities. The actual drilling depth capability of a rig may be less than or more than its rated depth capability due to numerous factors, including the size, weight and amount of the drill pipe on the rig. The intended well depth and the drill site conditions determine the amount of drill pipe and other equipment needed to drill a well. Generally, land
Technological advancements and trends in our industry affect the demand for certain types of equipment. In a continuing effort to improve our drilling rig fleet, we have installed top drives on 46 rigs operate(with five additional spare top drives available for installation), iron roughnecks on 53 rigs (with sixteen additional spare iron roughnecks available for installation), walking/skidding systems on 28 rigs and automatic catwalks on 31 rigs. These upgrades provide our clients with crewsdrilling rigs that have more varied capabilities for drilling in unconventional plays, and they improve our efficiency and safety.
In horizontal drilling, operators can utilize top drives to reach formations that may not be accessible with conventional rotary drilling. Top drives provide maximum torque and rotational control, improved well control and better hole conditioning. In recent years, oil and gas exploration and production companies have increased the use of
five"pad drilling" whereby a series of horizontal wells are drilled in succession by a walking or skidding drilling rig at a single pad-site location. Walking systems increase efficiency by allowing multiple wells to
six persons.be drilled on the same pad site and permitting the drilling rig to move between wells while drill pipe remains in the derrick, thus reducing move times and costs. Our walking system enables the drilling rig to move forward, backward, and side to side which affords the operator additional flexibility.
An iron roughneck is a remotely operated pipe handling feature on the rig floor, which is used to help reduce the occurrence of repetitive motion injuries and decrease drill pipe tripping time. An automated catwalk is a drill pipe handling feature used to raise drill pipe, drill collars, casing, and other necessary items to the drilling rig floor. Its function significantly reduces pick up and lay down time, thereby decreasing operator costs for handling casing.
The following table sets forth historical information regarding utilization for our drilling rig fleet:
| | | | | | | | | | | | | | | | | | | | |
| | | Years ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | | | 2007 | | | 2006 | |
Average number of operating rigs for the period | | | 71.0 | | | | 70.7 | | | | 67.4 | | | | 66.1 | | | | 58.5 | |
Average utilization rate | | | 59 | % | | | 41 | % | | | 89 | % | | | 89 | % | | | 96 | % |
|
| | | | | | | | | | | | | | |
| | Year ended December 31, |
| | 2013 | | 2012 | | 2011 | | 2010 | | 2009 |
| Average number of operating rigs for the period | 68.2 |
| | 65.0 |
| | 69.3 |
| | 71.0 |
| | 70.7 |
|
| Average utilization rate | 84 | % | | 87 | % | | 73 | % | | 59 | % | | 41 | % |
We believe that our drilling rigs and other related equipment are in good operating condition. Our employees perform periodic maintenance and minor repair work on our drilling rigs. We rely on various oilfield service companies for major repair work and overhaul of our drilling equipment when needed. We also engage in periodic improvement of our drilling equipment. In the event of major breakdowns or mechanical problems, our rigs could be subject to significant idle time and a resulting loss of revenue if the necessary repair services are not immediately available.
As of February 4, 2011,December 31, 2013, we own a fleet of 5540 trucks and related transportation equipment that we use to transport our drilling rigs to and from drilling sites. By owning our own trucks, we reduce the overall cost of rig moves and reduce downtime between rig moves. This is most beneficial to us in periods of high rig utilization and in regions where there is less pad drilling.
We obtain our contracts for drilling oil and gas wells either through competitive bidding or through direct negotiations with customers.clients. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. The contractContract terms we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, and the anticipated duration of the work to be performed. Generally, ourSpot market contracts generally provide for the drilling of a single well and typically permit the customerclient to terminate on short notice. However, we have entered into more longer-term drilling contracts duringDuring periods of high rig demand. In addition,demand, or for our newly constructed rigs, we generally construct new drilling rigs once we have enteredenter into longer-term drilling contracts for such rigs. contracts.
Currently, we have 32 contracts with terms of six months to threefour years in duration. Of these 32As of December 31, 2013, we have 39 drilling rigs operating under term contracts, which if not renewed at the end of their terms, 14 will expire by August 15, 2011, 11 will expire by February 15, 2012, one will expire by August 15, 2012 and six have a remaining term in excess of 18 months. We have one additional drilling rig under contract that we expect will begin operating in late February 2011 with a six month term.as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | | | Term Contract Expiration by Period |
| | | Total
Term Contracts | | Within
6 Months | | 6 Months
to 1 Year | | 1 Year to
18 Months | | 18 Months
to 2 Years | | 2 to 4 Years |
| United States | | 33 |
| | 18 |
| | 4 |
| | 5 |
| | 1 |
| | 5 |
|
| Colombia | | 6 |
| | — |
| | 6 |
| | — |
| | — |
| | — |
|
| | | 39 |
| | 18 |
| | 10 |
| | 5 |
| | 1 |
| | 5 |
|
As a provider of contract land drilling services, our business and the profitability of our operations depend on the level of drilling activity by oil and gas exploration and production companies operating in the geographic markets where we operate. The oil and gas exploration and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration and development activities. During periods of reduced drilling activity or excess rig capacity, price competition tends to increase and the profitability of daywork contracts tends to
decrease. In thisdecrease, and in such a competitive price environment, we may be more inclined to enter into turnkey contracts that expose us to greater risk of loss but which offer
higher potential contract profitability.
During the last three fiscal years, our drilling contracts have primarily been for daywork drilling and we have not performed any footage contract work. The following table presents, by type of contract, information about the total number of wells we completed for our
customersclients during each of the last three fiscal years.
| | | | | | | | | | | | |
| | | Years ended December 31, | |
Type of Contract | | 2010 | | | 2009 | | | 2008 | |
Daywork | | | 453 | | | | 323 | | | | 828 | |
Turnkey | | | 11 | | | | 14 | | | | 10 | |
Footage | | | — | | | | 1 | | | | 71 | |
| | | | | | | | | | | | |
Total number of wells | | | 464 | | | | 338 | | | | 909 | |
| | | | | | | | | | | | |
|
| | | | | | | | |
| | Year ended December 31, |
| Types of Contracts | 2013 | | 2012 | | 2011 |
| Daywork | 970 |
| | 881 |
| | 655 |
|
| Turnkey | 27 |
| | 11 |
| | 17 |
|
| Total number of wells | 997 |
| | 892 |
| | 672 |
|
Daywork Contracts. Under daywork drilling contracts, we provide a drilling rig and required personnel to our customerclient who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. Daywork drilling contracts specify the equipment to be used, the size of the hole and the depth of the well. Under a daywork drilling contract, the customerclient bears a large portion of the out-of-pocket drilling costs and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs. Turnkey Contracts.Under a turnkey contract, we agree to drill a well for our customerclient to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, we do not receive progress payments and are paid by our customerclient only after we have performed the terms of the drilling contract in full. The risks to us under a turnkey contract are substantially greater than on a well drilled on a daywork basis. This is primarily because under a turnkey contract we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalations and personnel. We employ or contract for engineering expertise to analyze seismic, geologic and drilling data to identify and reduce some of the drilling risks we assume. We use the results of this analysis to evaluate the risks of a proposed contract and seek to account for such risks in our bid preparation. We believe that our operating experience, qualified drilling personnel, risk management program, internal engineering expertise and access to proficient third-party engineering contractors have allowed us to reduce some of the risks inherent in turnkey drilling operations. We also maintain insurance coverage against some, but not all, drilling hazards. However, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations.
Footage Contracts. Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts as compared to daywork contracts. Similar to a turnkey contract, the risks to us on a footage contract are greater because we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalation and personnel. As with turnkey contracts, we manage this additional risk through the use of engineering expertise and bid the footage contracts accordingly. We also maintain insurance coverage against some, but not all, drilling hazards. However, the occurrence of uninsured or under-insured losses or operating cost overruns on our footage jobs could have a material adverse effect on our financial position and results of operations.
Production Services
DivisionSegment
Well ServicesServicing. We provide rig-basedOur well servicing rig fleet provides a range of services, including the completion of newly-drilled wells, maintenance of existing wells,and workover of existing wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful lives. Newly drilled wells require completion services to prepare the well for production. Well servicing rigs are frequently used to complete newly drilled wells to minimize the use of higher cost drilling rigs in the completion process. The completion process may involve selectively perforating the well casing in the productive zones to allow oil or gas to flow into the well bore, stimulating and testing these zones and installing the production string and other downhole equipment. The completion process typically requires a few days to several weeks, depending on the nature and type of the completion, and generally requires additional auxiliary equipment. Accordingly, completion services require less well-to-well mobilization of equipment and can provide higher operating margins than regular maintenance work. The demand for completion services is directly related to drilling activity levels, which are sensitive to changes in oil and gas prices.
Regular maintenance is
generally required throughout the life of a well to sustain optimal levels of oil and gas production.
We believe regular maintenance comprises the largest portion of our work in this business segment. Common maintenance services include repairing inoperable pumping equipment in an oil well and replacing defective tubing in a gas well. Our maintenance services involve relatively low-cost, short-duration jobs which are part of normal well operating costs. The need for maintenance does not directly depend on the level of drilling activity, although it is somewhat impacted by short-term fluctuations in oil and gas prices. Accordingly, maintenance services generally experience relatively stable demand; however, when oil or gas prices are too low to justify additional expenditures, operating companies may choose to temporarily shut in producing wells rather than incur additional maintenance costs.
In addition to periodic maintenance, producing oil and gas wells occasionally require major repairs or modifications called workovers, which are typically more complex and more time consuming than maintenance operations. Workover services include extensions of existing wells to drain new formations either through perforating the well casing to expose additional productive zones not previously produced, deepening well bores to new zones or the drilling of lateral well bores to improve reservoir drainage patterns. Our well
serviceservicing rigs are also used to convert former producing wells to injection wells through which water or carbon dioxide is then pumped into the formation for enhanced oil recovery operations. Workovers also include major subsurface repairs such as repair or replacement of well casing, recovery or replacement of tubing and removal of foreign objects from the well bore. These extensive workover operations are normally performed by a well
serviceservicing rig with additional specialized auxiliary equipment, which may include rotary drilling equipment, mud pumps, mud tanks and fishing tools, depending upon the particular type of workover operation. All of our well
serviceservicing rigs are designed to perform complex workover operations. A workover may require a few days to several weeks and generally requires additional auxiliary equipment. The demand for workover services is sensitive to oil and gas producers’ intermediate and long-term expectations for oil and gas prices.
Completion services involve the preparation of newly drilled wells for production. The completion process may involve selectively perforating the well casing in the productive zones to allow oil or gas to flow into the well bore, stimulating and testing these zones and installing the production string and other downhole equipment. We provide well service rigs to assist in this completion process. Newly drilled wells are frequently completed by well service rigs to minimize the use of higher cost drilling rigs in the completion process. The completion process typically requires a few days to several weeks, depending on the nature and type of the completion, and generally requires additional auxiliary equipment. Accordingly, completion services require less well-to-well mobilization of equipment and generally provide higher operating margins than regular maintenance work. The demand for completion services is directly related to drilling activity levels, which are sensitive to changes in oil and gas prices.
Well serviceservicing rigs are also used in the process of permanently closing oil and gas wells no longer capable of producing in economic quantities. Many well operators bid this work on a “turnkey” basis, requiring the service company to perform the entire job, including the sale or disposal of equipment salvaged from the well as part of the compensation received, and complying with state regulatory requirements. Plugging and abandonment work can
provide favorable operating margins and is less sensitive to oil and gas pricing than drilling and workover activity since well operators must plug a well in accordance with state regulations when it is no longer productive. We perform plugging and abandonment work throughout our core areas of operation in conjunction with equipment provided by other service companies.
When we provide well services, we
We typically bill customersclients for our well servicing on an hourly basis during the period that the rig providing services is actively working. As of February 4, 2010,December 31, 2013, our fleet of well serviceservicing rigs totaled 75 rigs.These
109 rigs, are locatedwhich we operate through 11 locations, mostly in Texas, serving the Gulf Coast and ArkLaTex regions, though we also have nine rigs in Louisiana and Mississippi and nine14 rigs in North Dakota. Our fleet is among the newest in the industry, consisting primarily of premium,ninety-nine 550 horsepower and ten 600 horsepower rigs capable of working at depths of 20,000 feet. Wireline Services. We provide both open and cased-hole wireline services with our fleetWireline trucks, like well servicing rigs, are utilized throughout the life of 86 wireline units, asa well. Wireline trucks are often used in place of February 4, 2011. We provide these servicesa well servicing rig when there is no requirement to remove tubulars from the well in Texas, Kansas, Colorado, Utah, Montana, North Dakota, Louisiana, West Virginia, Wyoming and Mississippi. order to make repairs.
Wireline services typically utilize a single truck equipped with a spool of wireline that is used to lower and raise a variety of specialized tools in and out of the wellbore. Electric wireline contains a conduit that allows signals to be transmitted to or from tools located in the well. These tools can be used to measure pressures and temperatures as well as the condition of the casing and the cement that holds the casing in place. In order for oil and gas exploration and production companies to better understand the reservoirs they are drilling or producing, they require logging services to accurately characterize reservoir rocks and fluids. We provide both open and cased-hole logging services, including the latest pulsed-neutron technology.
Other applications for wireline tools include placing equipment in or retrieving equipment from the wellbore, orinstalling bridge plugs, perforating the casing andin order to prepare the well for production, or cutting off pipe that is stuck in the well so that the free section can be recovered. Electric
As of December 31, 2013, our wireline contains a conduitservices fleet totaled 119 wireline units, including six offshore units, which we operate through 24 locations in Texas, Kansas, Colorado, Utah, Montana, North Dakota, Louisiana, Oklahoma and Wyoming.
Coiled Tubing Services. Coiled tubing is an important element of the production services industry today that allows signalsoperators to be transmitted to or from tools locatedcontinue production during service operations without shutting in the well. Wireline trucks are often used in placewell, thereby reducing the risk of formation damage. Coiled tubing services involve the use of a continuous metal pipe spooled on a large reel for oil and natural gas well service rig when thereapplications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, formation stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is no requirement to remove tubulars from thealso used for a number of horizontal well applications such as milling temporary plugs between frac stages. As of December 31, 2013, our coiled tubing business consists of nine onshore and four offshore units, which are currently deployed in order to make repairs. Wireline trucks, like well service rigs, are utilized throughout the life of a well.Texas and Louisiana. Fishing and Rental Services. Our rentalfishing and fishingrental tool business provides a range of specialized services and equipment that are utilized on a non-routine basis for both drilling and well servicing operations. Drilling and well serviceservicing rigs are equipped with a complement of tools to complete routine operations under normal conditions for most projects in the geographic area where they are employed. When downhole problems develop with drilling or servicing operations, or conditions require non-routine equipment, our customersclients will usually rely on a provider of rental and fishing tools to augment equipment that is provided with a typical drilling or well serviceservicing rig package. The important rental tools that we offer include air drilling equipment, foam units, power swivels, and blowout preventers. The term “fishing” applies to a wide variety of downhole operations designed to correct a problem that has developed when drilling or servicing a well. Often, the problem involves equipment that has become lodged in the well and cannot be removed without special equipment. Our
customersclients employ our technicians and our tools that are specifically suited to retrieve the trapped equipment, or “fish,” in order for operations to resume.
Our Production Services
Seasonality
All our production services operations are impacted by seasonal factors. Our business can be negatively impacted during the winter months due to inclement weather, fewer daylight hours, and holidays. Because our well service
servicing rigs,
wireline units and
wirelinecoiled tubing units are mobile, during periods of heavy snow, ice or rain, we may not be able to move our equipment between locations.
Clients
CustomersWe provide drilling services and production services to numerous major and independent oil and gas exploration and production companies that are active in the geographic areas in which we operate. The following table shows our three largest customersclients as a percentage of our total revenue for each of our last three fiscal years.
| |
| | |
Customer
| Total Revenue Percentage |
Total
Revenue
PercentageFiscal year ended December 31, 2013 | |
Fiscal Year Ended December 31, 2010:
Whiting Petroleum Company | 12.6 | | | % |
Ecopetrol | 10.7 | % |
| Apache Corporation | 5.9 | % |
| | |
17.7Fiscal year ended December 31, 2012 | % |
Whiting Petroleum Company | 10.1 | % |
| Ecopetrol | 9.7 | % |
| Apache Corporation | 5.5 | % |
| | |
8.9Fiscal year ended December 31, 2011 | % |
Chesapeake Operating, Inc.
Ecopetrol | | | 3.713.5 | % |
| Whiting Petroleum Corporation | 10.6 | % |
Fiscal Year Ended December 31, 2009:
Talisman Energy USA, Inc. | | | | |
Ecopetrol
| | | 16.23.6 | % |
Anadarko Petroleum Corporation
| | | 5.9 | % |
Cabot Oil and Gas Corporation
| | | 5.6 | % |
| |
Fiscal Year Ended December 31, 2008:
| | | | |
EOG Resources, Inc.
| | | 10.0 | % |
Ecopetrol
| | | 7.4 | % |
Anadarko Petroleum Corporation
| | | 6.4 | % |
Drilling Services
DivisionSegment
We encounter substantial competition from other drilling contractors. Our primary market areas are highly fragmented and competitive. The fact that drilling rigs are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry.
The drilling contracts we compete for are usually awarded on the basis of competitive bids. Our principal competitors are Helmerich & Payne, Inc., Precision Drilling Trust, Patterson-UTI Energy, Inc. and Nabors Industries, Ltd. In addition to pricing and rig availability, we believe the following factors are also important to our
customersclients in determining which drilling contractors to select:
the type and condition of each of the competing drilling rigs;
the mobility and efficiency of the rigs;
the quality of service and experience of the rig crews;
the safety records of the rigs;
our company;the offering of ancillary services; and
the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and drilling techniques.
While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment,
theour safety record,
of our
rigs andability to offer ancillary services, the experience of our rig crews
and the quality of service we provide to differentiate us from our competitors.
Contract drilling
Drilling companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. If demand for drilling services improves in a region where we operate, our competitors might respond by moving in suitable rigs from other regions. An influx of rigs from other regions could rapidly intensify competition and make any improvement in demand for drilling rigs in a particular region short-lived.
Some of our competitors have greater financial, technical and other resources than we do. Their greater capabilities in these areas may enable them to:
better withstand industry downturns;
compete more effectively on the basis of price and technology;
better retain skilled rig personnel; and
build new rigs or acquire and refurbish existing rigs so as to be able toand place rigsthem into service more quickly than us in periods of high drilling demand.
Production Services
DivisionSegment
The market for production services is highly competitive. Competition is influenced by such factors as price, capacity, availability of work crews, type and condition of equipment and reputation and experience of the service provider. We believe that an important competitive factor in establishing and maintaining long-term
customerclient relationships is having an experienced, skilled and well-trained work force. In recent years, many of our larger
customersclients have placed increased emphasis on the safety performance and quality of the crews, equipment and services provided by their contractors. We have devoted, and will continue to devote, substantial resources toward employee safety and training programs. Although we believe
customersclients consider all of these factors, price is generally the primary factor in determining which service provider is awarded the work. However, we believe that most
customersclients are willing to pay a slight premium for the quality and efficient service we provide.
The largest well
serviceservicing providers that we compete with are Key Energy Services, Basic Energy Services, Nabors Industries,
Complete ProductionSuperior Energy Services,
Inc. and CC Forbes. In addition, there are numerous smaller companies that compete in our well
serviceservicing markets.
The wireline market is dominated by Schlumberger Ltd. and Halliburton Company. These companies have a substantially larger asset base than we do and operate in all major U.S. oil and natural gas producing basins. Other competitors include Weatherford International, Baker
Atlas,Hughes, Superior Energy Services, Basic Energy Services, and
KeyC&J Energy Services. The market for wireline services is very competitive, but historically we have competed effectively with our competitors based on performance and strong
customerclient service.
The market for coiled tubing has increased due to the growth in deep well and horizontal drilling. Our primary competitors in the coiled tubing services market include Schlumberger Ltd., Baker Hughes, Halliburton Company, Key Energy Services, RPC Inc. and Superior Energy Services, Inc. In addition, numerous small companies compete in our coiled tubing services markets in the United States.
The fishing and rental tools market is fragmented compared to our other product lines. Companies
whichthat provide fishing services generally compete based on the reputation of their fishing tool operators and their relationships with
customers.clients. Competition for rental tools is sometimes based on price; however, in most cases, when a
customerclient chooses a specific fishing tool operator for a particular job, then the necessary rental equipment will be part of that job as well. Our primary competitors
include:in this service market include Baker
Oil Tools,Hughes, Weatherford International, Basic Energy Services, Key Energy Services, Quail Tools (owned by Parker Drilling) and Knight Oil Tools.
The need for well servicing, wireline,
coiled tubing, and fishing and rental services fluctuates primarily in relation to the price (or anticipated price) of oil and natural gas, which in turn is driven by the supply of and demand for oil and natural gas. Generally, as supply of
thosethese commodities decreases and demand increases, service and maintenance requirements increase as oil and natural gas producers attempt to maximize the productivity of their wells in a higher priced environment.
The level of our revenues, earnings and cash flows are substantially dependent upon, and affected by, the level of domestic and international oil and gas exploration and development activity, as well as the equipment capacity in any particular region. For a more detailed discussion, see Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
The materials and supplies we use in our drilling and production services operations include fuels to operate our
drilling and well service equipment, drilling mud, drill pipe, drill collars, drill bits and cement. We do not rely on a single source of supply for any of these items. While we are not currently experiencing any shortages, from time to time there have been shortages of drilling equipment and supplies during periods of high demand. Shortages could result in increased prices for drilling equipment or supplies that we may be unable to pass on to
customers.clients. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in
our obtaining drilling equipment or supplies could limit
our drilling operations and jeopardize our relations with
customers.clients. In addition, shortages of drilling equipment or supplies could delay and adversely affect our ability to obtain new contracts for our
drilling rigs, which could have a material adverse effect on our financial condition and results of operations.
Operating Risks and Insurance
Our operations are subject to the many hazards inherent in the contract land drilling business, including the risks of:
collapse of the borehole;
lost or stuck drill strings; and
damage or loss from natural disasters.
Any of these hazards can result in substantial liabilities or losses to us from, among other things:
suspension of drilling operations;
damage to, or destruction of, our property and equipment and that of others;
personal injury and loss of life;
damage to producing or potentially productive oil and gas formations through which we drill; and
We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Those risks include pollution liability in excess of relatively low limits. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our
customers.clients. However,
customersclients who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a
customerclient to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may not be able to maintain adequate insurance in the future at rates we consider reasonable.
Our current insurance coverage includes property insurance on our rigs, drilling equipment, production services equipment and real property. Our insurance coverage for property damage to our rigs, drilling equipment and production services equipment is based on our estimates of the cost of comparable used equipment to replace the insured property. The policy provides for a deductible on drilling rigs of $250,000$500,000 per occurrence ($500,000($750,000 deductible
for rigs with an insured value greater than $10 million), and a deductible on production services equipment of $100,000$250,000 per occurrence. Our third-party liability insurance coverage is $51$76 million per occurrence and in the aggregate, with a deductible of $260,000$260,000 per occurrence. We also carry insurance coverage for pollution liability up to $20 million with a deductible of $250,000. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of well disasters, extensive fire damage or damage to the environment. In addition, we generally carry insurance coverage to protect against certain hazards inherent in our turnkey contract drilling operations. This insurance covers “control-of-well,” including blowouts above and below the surface, redrilling, seepage and pollution. This policy provides coverage of $3 million, $5 million, $10 million, $15 million or $20 million, subject to a deductible of $150,000 or $250,000, depending on the area in which the well is drilled and its target depth, subject to a deductible of the greater of 15% of the well’s anticipated dry hole cost or $150,000.depth. This policy also provides care, custody and control insurance, with a limit of $1$1 million, subject to a $100,000$100,000 deductible. Employees
EmployeesWe currently have approximately 2550 employees. Approximately 300 of these employees are salaried administrative or supervisory3,650 employees. The restmajority of our employees are workingwork in operations for our Drilling Services DivisionSegment and Production Services DivisionSegment and are primarily compensated on an hourly basis. The number of employees in operations fluctuates depending on the utilization of our drilling rigs, well serviceservicing rigs, wireline units and wirelinecoiled tubing units at any particular time. None of our employment arrangements are subject to collective bargaining arrangements.
Our operations require the services of employees having the technical training and experience necessary to
obtainachieve proper operational standards. As a result, our operations depend, to a considerable extent, on the
continuing availability of such personnel. Although we have not encountered material difficulty in hiring and retaining employees in our operations, shortages of qualified personnel have occurred in our industry. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of training and experience to adequately operate our equipment, our operations could be materially and adversely affected. While we believe our wage rates are competitive and our relationships with our employees are satisfactory, a significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both. The occurrence of either of these events for a significant period of time could have a material and adverse effect on our financial condition and results of operations.
Facilities
FacilitiesOurWe lease our corporate office facilities are located at 1250 N.E. Loop 410, Suite 1000 San Antonio, Texas 78209 and are leased with payments escalating from $27,911 per month in January 2011 to $29,316 per month with a non-cancelable lease term expiring in December 2013.
78209. We conduct our business operations through 5067 other real estate locations, of which we own 15, in the United States (Texas, Oklahoma, Colorado, Utah, Montana, North Dakota, Pennsylvania, West Virginia, Wyoming, Mississippi, Arkansas, Louisiana and Kansas) and internationally in Colombia. These real estate locations are primarily used for regional offices and storage and maintenance yards. We own 11 of these real estate locations and the remaining 39 real estate locations are leased with payments ranging from $250 per month to $27,169 per month with non-cancelable lease terms expiring through August 2015.
Our operations are subject to stringent laws and regulations relating to containment, disposal and controlling the discharge of hazardous oilfield waste and other non-hazardous waste material into the environment, requiring removal and cleanup under certain circumstances, or otherwise relating to the protection of the environment. In addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands and coastal areas of the Gulf of Mexico, which are subject to special protective measures and which may expose us to additional operating costs and liabilities for accidental discharges of oil, natural gas, drilling fluids or contaminated water, or for noncompliance with other aspects of applicable laws. We are also subject to the requirements of the federal Occupational Safety and Health Act
(“OSHA”)(OSHA) and comparable state statutes. The OSHA hazard communication standard, the Environmental Protection Agency
(“EPA”)(EPA) “community right-to-know” regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens.
Environmental laws and regulations are complex and subject to frequent change. In some cases, they can impose liability for the entire cost of cleanup on any responsible party, without regard to negligence or fault, and can impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. We may also be exposed to environmental or other liabilities originating from businesses and assets that we purchased from others. Compliance with applicable environmental laws and regulations has not, to date, materially affected our capital expenditures, earnings or competitive position, although compliance measures have added to our costs of operating drilling equipment in some instances. We do not expect to incur material capital expenditures in our next fiscal year in order to comply with current environment control regulations. However, our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.
There are a variety of regulatory developments, proposals or requirements and legislative initiatives that have been introduced in the United States and international regions in which we operate that are focused on
restricting the emission of carbon dioxide, methane and other greenhouse gases. Among these developments are the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol” (an internationally applied protocol, which has been ratified in Colombia, one of our reporting segments)which is a location where we provide drilling services), the Regional Greenhouse Gas Initiative or “RGGI” in the Northeastern United States, and the Western Regional Climate Action Initiative in the Western United States, including partners states New Mexico, Utah, and Montana and observer states Colorado and Wyoming.
States.
The U.S. Congress has
been actively consideringfrom time to time considered legislation to reduce emissions of greenhouse gases, primarily through the development of greenhouse gas cap and trade programs. In
June of 2009, the U.S. House of Representatives passed a cap and trade bill known as the American Clean Energy and Security Act of 2009, which is now being considered by the U.S. Senate, among other alternative bills. In addition, more than one-third of the states already have begun implementing legal measures to reduce emissions of greenhouse gases.
In 2007, the United States Supreme Court in Massachusetts, et al. v. EPA, held that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act. On December 7, 2009, the EPA responded to the Massachusetts, et al. v. EPA decision and issued a finding that the current and projected concentrations of greenhouse gases in the atmosphere threaten the public health and welfare of current and future generations, and that certain greenhouse gases from
new motor vehicles
and motor vehicle engines contribute to the atmospheric concentrations of greenhouse gases and hence to the threat of climate change.
On September 22, 2009,
Based on these findings, in 2010 the EPA finalizedadopted two sets of regulations that restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of greenhouse gases from motor vehicles and another that requires certain construction and operating permit reviews for greenhouse gas emissions from certain large stationary sources. The stationary source final rule requiring nation-wide reportingaddresses the permitting of greenhouse gas emissions beginning January 1, 2010. The rule applies primarilyfrom stationary sources under the Clean Air Act Prevention of Significant Deterioration construction and Title V operating permit programs, pursuant to large facilities emitting 25,000 metric tons or morewhich these permit programs have been "tailored" to apply to certain stationary sources of carbon dioxide-equivalent greenhouse gas emissions per year, andin a multi-step process, with the largest sources first subject to most upstream suppliers of fossil fuels and industrial greenhouse gas, as well as to manufacturers of vehicles and engines.permitting. In addition, the EPA recently proposed a ruleadopted rules requiring the monitoring and reporting of greenhouse gases from certain sources, including, among others, onshore oil and natural gas production facilities.
In April 2012, the EPA issued regulations specifically applicable to the oil and gas industry that will require operators to significantly reduce volatile organic compounds, or VOC, emissions from natural gas wells that are hydraulically fractured through the use of “green completions” to capture natural gas that would
in general, require facilitiesotherwise escape into the air. The EPA also issued regulations that
emit more than 25,000 tons per yearestablish standards for VOC emissions from several types of
greenhouseequipment at natural gas
equivalents to obtain permits to demonstrate that best practiceswell sites, including storage tanks, compressors, dehydrators and
technology are being used to minimize greenhouse gas emissions.pneumatic controllers.
Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Any additional costs or operating restrictions associated with legislation or regulations regarding greenhouse gas emissions could have a material adverse effect on our operating results and cash flows. In addition, these developments could curtail the demand for fossil fuels such as oil and gas in areas of the world where our
customersclients operate and thus adversely affect demand for our services, which may in turn adversely affect our future results of operations. Finally, we cannot predict with any certainty whether changes to temperature, storm intensity or precipitation patterns as a result of climate change will have a material impact on our operations.
Hydraulic fracturing is a commonly used process that involves injection of water, sand, and a minor amount of certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. The federal Energy Policy Act of 2005 amended the Underground Injection Control provisions of the federal Safe Drinking Water Act (SDWA) to exclude certain hydraulic fracturing practices from the definition of "underground injection." The EPA has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling andasserted regulatory authority over certain hydraulic fracturing activities.activities involving diesel fuel and has developed draft guidance relating to such practices. In addition, repeal of the SDWA exclusion of hydraulic fracturing has been advocated by certain advocacy organizations and others in the public. Congress has from time to time considered legislation to repeal the exemption for hydraulic fracturing from the SDWA, which would have the effect of allowing the EPA to promulgate new regulations and permitting requirements for hydraulic fracturing, and to require the disclosure of the chemical constituents of hydraulic fracturing fluids to a regulatory agency, which would make the information public via the Internet.
Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a study of the potential environmental impacts of hydraulic fracturing, the final results of which are expected in 2014. In addition, in April 2012, the EPA issued the first federal air standards for natural gas wells that are hydraulically fractured, which will require operators to significantly reduce VOC emissions through the use of “green completions” to capture natural gas that would otherwise escape into the air. These new rules address emissions of various pollutants frequently associated with oil and natural gas production and processing activities by, among other things, requiring new or reworked hydraulically-fractured gas wells to control emissions through flaring until 2015, after which reduced emission (or “green”) completions must be used. The rules also establish specific new requirements, which were effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants, and certain other equipment. On September 23, 2013, the EPA published amendments to the rule which would, among other things, provide additional time for recently constructed, modified or reconstructed storage tanks to install emission controls. The EPA is conductingcontinuing to consider other aspects of the new rules and may propose additional amendments by the end of 2013 or in early 2014. These rules may require a comprehensive research study onnumber of modifications to our clients’ and our own operations, including the potential adverse effects thatinstallation of new equipment to control emissions. Compliance with such rules could result in additional costs for us and our clients, including increased capital expenditures and operating costs, which may adversely impact our cash flows and results of operations.
The EPA is also developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing mayactivities and plans to propose these standards by 2014. The U.S. Department of the Interior has also proposed regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing fluid constituents.
In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, that would require, with some exceptions, disclosure of constituents of hydraulic fracturing fluids, or that would impose higher taxes, fees or royalties on water qualitynatural gas production. Moreover, public debate over hydraulic fracturing and public health. It is possible that resultingshale gas production has been increasing, and has resulted in delays of well permits in some areas.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, incurred by our clients. The adoption of any federal, state
andor local laws
andor the implementation of regulations
might be imposed on fracturing activities. The potential adoptionor ordinances restricting or increasing the costs of
federal and state legislative and regulatory initiatives related to hydraulic fracturing could
result in operating restrictions or delayscause a decrease in the completion of
new oil and
natural gas
wells. A decline in the drilling of new wells and
relatedan associated decrease in demand for our drilling and well servicing activities,
caused by these initiativesany or all of which could adversely affect our financial position, results of operations and cash flows.
In addition, our business depends on the demand for land drilling and production services from the oil and gas industry and, therefore, is affected by tax, environmental and other laws relating to the oil and gas industry generally, by changes in those laws and by changes in related administrative regulations. It is possible that these laws and regulations may in the future add significantly to our operating costs or those of our
customers,clients, or otherwise directly or indirectly affect our operations.
Our wireline operations involve the use of radioactive isotopes along with other nuclear, electrical, acoustic, and mechanical devices. Our activities involving the use of isotopes are regulated by the U.S. Nuclear Regulatory Commission and specified agencies of certain states. Additionally, we use high explosive charges for perforating casing and formations, and we use various explosive cutters to assist in wellbore cleanout. Such operations are regulated by the U.S. Department of Justice, Bureau of Alcohol, Tobacco, Firearms, and Explosives and require us to obtain licenses or other approvals for the use of densitometers as well as explosive charges. We have obtained these licenses and approvals when necessary and believe that we are in substantial compliance with these federal requirements.
Among the services we provide, we operate as a motor carrier for the transportation of our own equipment and therefore are subject to regulation by the U.S. Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.
Interstate motor carrier operations are subject to safety requirements prescribed by the U.S. Department of Transportation. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations.
From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
Our Website address iswww.pioneerdrlg.comwww.pioneeres.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, are available free of charge through our Website as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the Securities and Exchange Commission. The public may read and copy these materials at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. For additional information on the operations of the Securities and Exchange Commission’s Public Reference Room, please call 1-800-SEC-0330. In addition, the Securities and Exchange Commission maintains an Internet site atwww.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically. We have also posted on our Website our: Charters for the Audit, Compensation, and Nominating and Corporate Governance Committees of our Board; Code of Business Conduct and Ethics; Rules of Conduct;Corporate Governance Guidelines; and Company Contact Information. Information on our website is not incorporated into this report or otherwise made part of this report.
The information set forth in this Item 1A should be read in conjunction with the rest of the information included in this report, including “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and the
historical financial statements and related notes this report contains. While we attempt to identify, manage and mitigate risks and uncertainties associated with our business to the extent practical under the circumstances, some level of risk and uncertainty will always be present. Additional risks and uncertainties that are not presently known to us or that we currently believe are immaterial also may negatively impact our business, financial condition or operating results.
Set forth below are various risks and uncertainties that could adversely impact our business, financial condition, results of operations and cash flows.
Risks Relating to the Oil and Gas Industry
We derive all our revenues from companies in the oil and gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and gas prices.
As a provider of contract land drilling services and oil and gas production services, our business depends on the level of exploration and production activity in the geographic markets where we operate. The oil and gas exploration and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration and development activities. Oil and gas prices, and market expectations of potential changes in those prices, significantly affect the levels of those activities. Worldwide political, economic, and military events as well as natural disasters have contributed to oil and gas price volatility and are likely to continue to do so in the future. Any prolonged reduction in the overall level of exploration and development activities, whether resulting from changes in oil and gas prices or otherwise, could materially and adversely affect us
in many ways by negatively impacting:
our revenues, cash flows and profitability;
the fair market value of our drilling rig fleet and production service assets;
services equipment;our ability to maintain or increase our borrowing capacity;
our ability to obtain additional capital to finance our business and make acquisitions, and the cost of that capital; and
our ability to retain skilled rig personnel whom we would need in the event of an upturn in the demand for our services.
Depending on the market prices of oil and gas, oil and gas exploration and production companies may cancel or curtail their drilling programs and may lower production spending on existing wells, thereby reducing demand for our services. Many factors beyond our control affect oil and gas prices, including:
the cost of exploring for, producing and delivering oil and gas;
the discovery rate of new oil and gas reserves;
the rate of decline of existing and new oil and gas reserves;
available pipeline and other oil and gas transportation capacity;
the levels of oil and gas storage;
the ability of oil and gas exploration and production companies to raise capital;
economic conditions in the United States and elsewhere;
actions by OPEC, the Organization of Petroleum Exporting Countries;
political instability in the Middle East and other major oil and gas producing regions;
governmental regulations, both domestic and foreign;
domestic and foreign tax policy;
weather conditions in the United States and elsewhere;
the pace adopted by foreign governments for the exploration, development and production of their national reserves;
the price of foreign imports of oil and gas; and
the overall supply and demand for oil and gas.
Oil and gas prices have been volatile historically and, we believe, will continue to be so in the future. During
late 2008 and continuing into late 2009, oil and natural gas prices fell significantly below the levels seen in
late 2008, and whilemid-2008. While oil prices have
improved during 2010,generally recovered from the low levels in late 2008, natural gas prices have remained depressed. Future declines in and volatility in oil and gas prices could materially and adversely affect our business and financial results.
Risks Relating to Our Business
Reduced demand for or excess capacity of drilling services or production services could adversely affect our profitability.
Our profitability in the future will depend on many factors, but largely on pricing and utilization rates for our drilling and production services. A reduction in the demand for drilling rigs or an increase in the supply of drilling rigs, whether through new construction or refurbishment, could decrease the dayrates and utilization rates for our drilling services, which would adversely affect our revenues and profitability. An increase in supply of well
serviceservicing rigs, wireline
units, coiled tubing units, and fishing and rental tools
and equipment, without a corresponding increase in demand, could similarly decrease the pricing and utilization rates of our production services, which would adversely affect our revenues and profitability.
We experienced a substantial decrease in revenue and utilization rates during the last quarter of 2008 and during 2009. During 2010, revenue and utilization rates modestly increased and we expect continued modest increases in 2011.
We operate in a highly competitive, fragmented industry in which price competition could reduce our profitability.
We encounter substantial competition from other drilling contractors and other oilfield service companies. Our primary market areas are highly fragmented and competitive. The fact that drilling and
well service rigsproduction services equipment are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry and may result in an oversupply of
rigsequipment in an area. Contract drilling companies and other oilfield service companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. If demand for drilling or production services improves in a region where we operate, our competitors might respond by moving in suitable rigs
and production services equipment from other regions. An influx of
rigsequipment from other regions could rapidly intensify competition, reduce profitability and make any improvement in demand for drilling or production services short-lived.
Most drilling services contracts and production services contracts are awarded on the basis of competitive bids, which also results in price competition. In addition to pricing and
rigequipment availability, we believe the following factors are also important to our
customersclients in determining which drilling services or production services provider to select:
the type and condition of each of the competing drilling rigs, well servicing rigs, wireline units and well service rigs;
coiled tubing units;
the mobility and efficiency of the rigs;
equipment;the quality of service and experience of the rig crews;
the safety recordsrecord of the rigs;
company providing the services;the offering of ancillary services; and
the ability to provide drilling and production services equipment adaptable to, and personnel familiar with, new technologies and drilling and production techniques.
While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment, theour safety record, of our rigs, our ability to offer ancillary services, the experience of our crews and the quality of service and experience of our rig crewswe provide to differentiate us from our competitors. This strategy is less effective aswhen lower demand for
drilling and production services
or an oversupply of drilling and well service rigs intensifies price competition and makes it more difficult for us to compete on the basis of factors other than price. In all of the markets in which we compete, an oversupply of
drilling rigs
or production services equipment can cause greater price competition, which can reduce our profitability.
We face competition from many competitors with greater resources.
Some of our competitors have greater financial, technical and other resources than we do. Their greater capabilities in these areas may enable them to:
better withstand industry downturns;
compete more effectively on the basis of price and technology;
retain skilled rig personnel; and
build new rigs or acquire and refurbish existing rigs so as to be able toand place rigsthem into service more quickly than us in periods of high drilling demand.
Additionally, although
Technological advancements and trends in our industry affect the demand for certain types of equipment.
Technological advancements and trends in our industry also affect the demand for certain types of equipment. During 2013, the demand for traditional drilling rigs in vertical markets has softened due to increased demand for drilling rigs that are able to drill horizontally. In addition, oil and gas exploration and production companies have increased the use of "pad drilling" in recent years whereby a series of horizontal wells are drilled in succession by a walking or skidding drilling rig at a single pad-site location. Pad drilling has improved the productivity of exploration and production activities which could reduce the demand for drilling rigs, particularly those that do not have the ability to walk or skid and to drill horizontal wells.
Although we take measures to ensure that we use advanced technologies for drilling and production services equipment, changes in technology or improvements in our competitors’ equipment could make our equipment less competitive or require significant capital investments to keep our equipment
competitive.competitive, which could have an adverse effect on our financial condition and operating results.
Unexpected cost overruns on our turnkey drilling jobs and our footage contracts could adversely affect our financial position and our results of operations.
We have historically derived a portion of our revenues from turnkey drilling contracts, and we expect turnkey contracts will continue to represent a component of our future revenues. The occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations. Under a typical turnkey drilling contract, we agree to drill a well for our
customerclient to a specified depth and under specified conditions for a fixed price. We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well
logging.Underlogging. Under typical turnkey drilling arrangements, we do not receive progress payments and are paid by our
customerclient only after we have performed the terms of the drilling contract in full. For these reasons, the risk to us under a turnkey drilling contract is substantially greater than for a well drilled on a daywork basis because we must assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalations and personnel. Similar to our turnkey contracts, under a footage contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract. In addition, since we are only paid by our
customersclients after we have performed the terms of the drilling contract in full, our liquidity can be affected by the number of turnkey and footage contracts that we enter into.
Although we attempt to obtain insurance coverage to reduce certain of the risks inherent in our turnkey drilling operations, adequate coverage may be unavailable in the future and we might have to bear the full cost of such risks, which could have an adverse effect on our financial condition and results of operations.
Our operations involve operating hazards, which, if not insured or indemnified against, could adversely affect our results of operations and financial condition.
Our operations are subject to the many hazards inherent in the drilling and well
servicesservicing industries, including the risks of:
collapse of the borehole;
damaged or lost drilling equipment; and
damage or loss from natural disasters.
Any of these hazards can result in substantial liabilities or losses to us from, among other things:
suspension of operations;
damage to, or destruction of, our property and equipment and that of others;
personal injury and loss of life;
damage to producing or potentially productive oil and gas formations through which we drill; and
We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Those risks include, among other things, pollution liability in excess of relatively low limits. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our
customers.clients. However,
customersclients who provide contractual indemnification protection may not in all cases maintain adequate insurance or otherwise have the financial resources necessary to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a
customerclient to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may be unable to maintain adequate insurance in the future at rates we consider reasonable.
We could be adversely affected if shortages of equipment, supplies or personnel occur.
From time to time there have been shortages of drilling and production services equipment and supplies during periods of high demand which we believe could recur. Shortages could result in increased prices for drilling and production services equipment or supplies that we may be unable to pass on to
customers.clients. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in our obtaining drilling and production services equipment or supplies could limit drilling and production services operations and jeopardize our relations with
customers.clients. In addition, shortages of drilling and production services equipment or supplies could delay and adversely affect our ability to obtain new contracts for our rigs, which could have a material adverse effect on our financial condition and results of operations.
Our strategy of constructing drilling rigs during periods of peak demand requires that we maintain an adequate supply of drilling rig components to complete our rig building program. Our suppliers may be unable to continue providing us the needed drilling rig components if their manufacturing sources are unable to fulfill their commitments.
Our operations require the services of employees having the technical training and experience necessary to obtainachieve the proper operational results. As a result, our operations depend, to a considerable extent, on the continuing availability of such personnel. Shortages of qualified personnel have occurred in our industry. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the
requisite level of training and experience to adequately operate our equipment, our operations could be materially and adversely affected. A significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both. The occurrence of either of these events for a significant period of time could have a material
and adverse effect on our financial condition and results of operations.
Our acquisition strategy exposes us to various risks, including those relating to difficulties in identifying suitable acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements.
As a key component of our business strategy, we have pursued and intend to continue to pursue acquisitions of complementary assets and businesses. For example, since September 1999, we have significantly expanded our drilling rig fleet
by adding 35 rigs through acquisitions and
by adding 31 rigs through the construction of rigs from new and used
components. In addition,components, and in March 2008, we
completed the acquisition of theacquired two production services businesses
which significantly expanded our service offerings to include well servicing, wireline services and fishing and rental services. On December 31, 2011, we acquired the coiled tubing services business of
WEDGE and Competition during the first quarter of 2008. We have continuedGo-Coil to
invest in the expansion ofcomplement our
operations and plan to add a total of six well service rigs and 14 wireline units in the first half of 2011.existing production services offerings.
Our acquisition strategy in general, and our recent acquisitions in particular, involve numerous inherent risks, including:
unanticipated costs and assumption of liabilities and exposure to unforeseen liabilities of acquired businesses, including environmental liabilities;
difficulties in integrating the operations and assets of the acquired business and the acquired personnel;
limitations on our ability to properly assess and maintain an effective internal control environment over an acquired business in order to comply with applicable periodic reporting requirements;
potential losses of key employees and customersclients of the acquired businesses;
risks of entering markets in which we have limited prior experience; and
increases in our expenses and working capital requirements.
The process of integrating an acquired business may involve unforeseen costs and delays or other operational, technical and financial difficulties that may require a disproportionate amount of management attention and financial and other resources.
Possible future acquisitions may be for purchase prices significantly higher than those we paid for previous acquisitions. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
In addition, we may not have sufficient capital resources to complete additional acquisitions. Historically, we have funded
business acquisitions and the growth of our rig fleet through a combination of debt and equity financing. We may incur substantial additional indebtedness to finance future acquisitions and also may issue equity securities or convertible securities in connection with such acquisitions. Debt service requirements could represent a
significant burden on our results of operations and financial condition and the issuance of additional equity or convertible securities could be dilutive to our existing shareholders. Furthermore, we may not be able to obtain additional financing on satisfactory terms.
Even if we have access to the necessary capital, we may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms or successfully acquire identified targets.
Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.
In connection with
Our indebtedness is primarily a result of the two production services businesses that we acquired in 2008 and the acquisition of the production services businessesGo-Coil in 2011. At December 31, 2013, our total debt balance of WEDGE and Competition in March 2008, we entered into a senior secured revolving credit facility (the “Revolving Credit Facility”) which was later amended in October 2009 and February 2010. In March 2010, we issued $250$502.5 million primarily consists of Senior Notes with a coupon interest rate of 9.875% that are due in 2018 (the “Senior Notes”). We received $234.8$419.6 million of net proceeds from the issuance of the Senior Notes after deductions were made for the $10.6 million of original issue discount and $4.6 million for underwriters’ fees and other debt offering costs. The net proceeds were used to repay a portion of the borrowings outstanding under our Senior Notes. As of December 31, 2013, our Revolving Credit Facility. AsFacility had a $80.0 million balance outstanding, with a current availability of December 31, 2010, our total debt was $280.9 million.$156.0 million. Our current and future indebtedness could have important consequences, including:
impairing our ability to make investments and obtain additional financing for working capital, capital expenditures, acquisitions or other general corporate purposes;
limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make principal and interest payments on our indebtedness;
making us more vulnerable to a downturn in our business, our industry or the economy in general as a substantial portion of our operating cash flow could be required to make principal and interest payments on our indebtedness, making it more difficult to react to changes in our business, and in industry and market conditions;
limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
limiting our ability to obtain additional financing that may be necessary to operate or expand our business;
putting us at a competitive disadvantage to competitors that have less debt; and
increasing our vulnerability to rising interest rates.
We anticipate that our cash generated by operations and our ability to borrow under the currently unused portion of our Revolving Credit Facility should allow us to meet our routine financial obligations for
at least the
foreseeable future.next twelve months. However, our ability to make payments on our indebtedness, and to fund planned capital expenditures, will depend on our ability to generate cash in the future. This, to a certain extent, is subject to conditions in the oil and gas industry, general economic and financial conditions, competition in the markets where we operate, the impact of legislative and regulatory actions on how we conduct our business and other factors, all of which are beyond our control. If our business does not generate sufficient cash flow from operations to service our outstanding indebtedness, we may have to undertake alternative financing plans, such as:
refinancing or restructuring our debt;
reducing or delaying acquisitions or capital investments, such as refurbishments of our rigs and related equipment; or
seeking to raise additional capital.
However, we may be unable to implement alternative financing plans, if necessary, on commercially reasonable terms or at all, and any such alternative financing plans might be insufficient to allow us to meet our debt obligations. If we are unable to generate sufficient cash flow or are otherwise unable to obtain the funds required to make principal and interest payments on our indebtedness, or if we otherwise fail to comply with the various covenants in our Revolving Credit Facility or other instruments governing any future indebtedness, we could be in default under the terms of our Revolving Credit Facility or such instruments. In the event of a default, the lenders under our Revolving Credit Facility could elect to declare all the loans made under such facility to be due and payable together with accrued and unpaid interest and terminate their commitments thereunder and we or one or more of our subsidiaries could be forced into bankruptcy or liquidation. Any of the foregoing consequences could materially and adversely affect our business, financial condition, results of operations and prospects.
Our Revolving Credit Facility and our Senior Notes impose restrictions on us that may affect our ability to successfully operate our business.
Our Revolving Credit Facility limits our ability to take various actions, such as:
limitations on the incurrence of additional indebtedness;
restrictions on investments, capital expenditures, mergers or consolidations, asset dispositions, acquisitions, transactions with affiliates and other transactions without the lenders’ consent; and
limitation on dividends and distributions.
In addition, our Revolving Credit Facility requires us to maintain certain financial ratios and to satisfy certain financial conditions, which may require us to reduce our debt or take some other action in order to comply with them.
The Indenture governing our Senior Notes contains certain restrictions on our and certain of our subsidiaries’ ability to:
repurchase stock or redeem subordinated debt or make other restricted payments;
incur, assume or guarantee additional indebtedness or issue disqualified stock;
create liens on the our assets;
enter into sale and leaseback transactions;
pay dividends, engage in loans, or transfer other assets from certain of our subsidiaries;
consolidate with or merge with or into, or sell all or substantially all of our properties to another person;
enter into transactions with affiliates; and
enter into new lines of business.
The failure to comply with any of these restrictions or conditions
some of which become more restrictive over time, such as financial ratios or covenants, would cause an event of default under our Revolving Credit Facility or our Senior Notes. An event of default, if not waived, could result in acceleration of the outstanding indebtedness, in which case the debt would become immediately due and payable. If this occurs, we may not be able to pay our debt or borrow sufficient funds to refinance it. Even if new financing is available, it may not be available on terms that are acceptable to us. These restrictions could also limit our ability to obtain future financing, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We also may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our Revolving Credit Facility and our Senior Notes.
Our international operations are subject to political, economic and other uncertainties not encountered in our domestic operations.
As we continue to implement our strategy of expanding into areas outside the United States, our
Our international operations
will beare subject to political, economic and other uncertainties not generally encountered in our U.S.
operations. These willoperations which include, among potential others:
risks of war, terrorism, civil unrest and kidnapping of employees;
expropriation, confiscation or nationalization of our assets;
renegotiation or nullification of contracts;
the inability to repatriate earnings or capital due to laws limiting the right and ability of foreign subsidiaries to pay dividends and remit earnings to affiliated companies;
changing political conditions and changing laws and policies affecting trade and investment;
concentration of customers;
clients;regional economic downturns;
the overlap of different tax structures;
the burden of complying with multiple and potentially conflicting laws;
the risks associated with the assertion of foreign sovereignty over areas in which our operations are conducted;
the risks associated with any lack of compliance with the Foreign Corrupt Practices Act of 1977 ("FCPA") or other anti-corruption laws;
the risks associated with fluctuating currency values, hard currency shortages and controls of foreign currency exchange;
difficulty in collecting international accounts receivable; and
potentially longer payment cycles.
Our international operations are concentrated in Colombia and
most of our drilling contracts are
currently with one
customer,client, Ecopetrol. We believe our relationship with Ecopetrol is good; however, the loss of this large
customerclient could have an adverse effect on our business, financial condition and result of operations.
Our international operations may also face the additional risks of fluctuating currency values, hard currency shortages and controls of foreign currency exchange.
Additionally,
in some jurisdictions, we may be subject to foreign governmental regulations favoring or requiring the awarding of contracts to local contractors or requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These regulations could adversely affect our ability to compete.
We are committed to doing business in accordance with applicable anti-corruption laws and our code of conduct and ethics. We are subject, however, to the risk that our employees and agents may take action determined to be in violation of anti-corruption laws, including the FCPA or other similar laws. Any violation of the FCPA or other applicable anti-corruption laws could result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions and might materially adversely affect our business, results of operations or financial condition. In addition, actual or alleged violations could damage our reputation and ability to do business. Further, detecting, investigating, and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.
Our operations are subject to various laws and governmental regulations that could restrict our future operations and increase our operating costs.
Many aspects of our operations are subject to various federal, state and local laws and governmental regulations, including laws and regulations governing:
remediation of contamination;
preservation of natural resources;
Our operations are subject to stringent federal, state and local laws, rules and regulations governing the protection of the environment and human health and safety. Some of those laws, rules and regulations relate to the disposal of hazardous substances, oilfield waste and other waste materials and restrict the types, quantities and concentrations of those substances that can be released into the environment. Several of those laws also require removal and remedial action and other cleanup under certain circumstances, commonly regardless of fault. Our operations routinely involve the handling of significant amounts of waste materials, some of which are classified as hazardous substances. Planning, implementation and maintenance of protective measures are required to prevent accidental discharges. Spills of oil, natural gas liquids, drilling fluids and other substances may subject us to penalties and cleanup requirements. Handling, storage and disposal of both hazardous and non-hazardous wastes are also subject to these regulatory requirements. In addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands, which are subject to special protective measures and which may expose us to
additional operating costs and liabilities for accidental discharges of oil, gas, drilling fluids, contaminated water or other substances, or for noncompliance with other aspects of applicable laws and regulations.
The federal Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource Conservation and Recovery Act, the federal Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, the Safe Drinking Water Act,
or SDWA, the federal Outer Continental Shelf Lands Act, the Occupational Safety and Health Act, or OSHA, and their state counterparts and similar statutes are the primary statutes that impose the requirements described above and provide for civil, criminal and administrative penalties and other sanctions for violation of their requirements. The OSHA hazard communication standard, the Environmental Protection Agency “community right-to-know” regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens. In addition, CERCLA, also known as the “Superfund” law, and similar state statutes impose strict liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered responsible for the release or threatened release of hazardous substances into the environment. These persons include the current owner or operator of a facility where a release has occurred, the owner or operator of a facility at the time a release occurred, and companies that disposed of or arranged for the disposal of hazardous substances found at a particular site. This liability may be joint and several. Such liability, which may be imposed for the conduct of others and for conditions others have caused, includes the cost of removal and remedial action as well as damages to natural resources. Few defenses exist to the liability imposed by environmental laws and regulations. It is also common for third parties to file claims for personal injury and property damage caused by substances released into the environment.
Environmental laws and regulations are complex and subject to frequent change. Failure to comply with governmental requirements or inadequate cooperation with governmental authorities could subject a responsible party to administrative, civil or criminal action. We may also be exposed to environmental or other liabilities originating from businesses and assets which we acquired from others. Our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination or regulatory noncompliance may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.
There are a variety of regulatory developments, proposals or requirements and legislative initiatives that have been introduced in the United States and international regions in which we operate that are focused on restricting the emission of carbon dioxide, methane and other greenhouse gases. Among these developments are the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol” (an internationally applied protocol, which has been ratified in Colombia,
one of our reporting segments)which is a location where we provide drilling services), the Regional Greenhouse Gas Initiative or “RGGI” in the Northeastern United States, and the Western Regional Climate Action Initiative in the Western United
States, including partners states New Mexico, Utah, and Montana and observer states Colorado and Wyoming.States.
The U.S. Congress has
been actively consideringfrom time to time considered legislation to reduce emissions of greenhouse gases, primarily through the development of greenhouse gas cap and trade programs. In
June of 2009, the U.S. House of Representatives passed a cap and trade bill known as the American Clean Energy and Security Act of 2009, which is now being considered by the U.S. Senate, among other alternative bills. In addition, more than one-third of the states already have begun implementing legal measures to reduce emissions of greenhouse gases.
In 2007, the United States Supreme Court in Massachusetts, et al. v. EPA, held that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act. On December 7, 2009, the EPA responded to the Massachusetts, et al. v. EPA decision and issued a finding that the current and projected concentrations of greenhouse gases in the atmosphere threaten the public health and welfare of current and future generations, and that certain greenhouse gases from
new motor vehicles
and motor vehicle engines contribute to the atmospheric concentrations of greenhouse gases and hence to the threat of climate change.
On September 22, 2009,
Based on these findings, in 2010 the EPA finalizedadopted two sets of regulations that restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of greenhouse gases from motor vehicles and another that requires certain construction and operating permit reviews for greenhouse gas emissions from certain large stationary sources. The stationary source final rule requiring nation-wide reportingaddresses the permitting of greenhouse gas emissions beginning January 1, 2010. The rule applies primarilyfrom stationary sources under the Clean Air Act Prevention of Significant Deterioration construction and Title V operating permit programs, pursuant to large facilities emitting 25,000 metric tons or morewhich these permit programs have been "tailored" to apply to certain stationary sources of carbon dioxide-equivalent greenhouse gas emissions per year, andin a multi-step process, with the
largest sources first subject to most upstream suppliers of fossil fuels and industrial greenhouse gas, as well as to manufacturers of vehicles and engines.permitting. In addition, the EPA recently proposed a ruleadopted rules requiring the monitoring and reporting of greenhouse gases from certain sources, including, among others, onshore oil and natural gas production facilities.
In April 2012, the EPA issued regulations specifically applicable to the oil and gas industry that will require operators to significantly reduce volatile organic compounds, or VOC, emissions from natural gas wells that are hydraulically fractured through the use of “green completions” to capture natural gas that would
in general, require facilitiesotherwise escape into the air. The EPA also issued regulations that
emit more than 25,000 tons per yearestablish standards for VOC emissions from several types of
greenhouseequipment at natural gas
equivalents to obtain permits to demonstrate that best practiceswell sites, including storage tanks, compressors, dehydrators and
technology are being used to minimize greenhouse gas emissions.pneumatic controllers.
Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Any additional costs or operating restrictions associated with legislation or regulations regarding greenhouse gas emissions could have a material adverse effect on our operating results and cash flows. In addition, these developments could curtail the demand for fossil fuels such as oil and gas in areas of the world where our
customersclients operate and thus adversely affect demand for our services, which may in turn adversely affect our future results of operations. Finally, we cannot predict with any certainty whether changes to temperature, storm intensity or precipitation patterns as a result of climate change will have a material impact on our operations.
The EPA has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities. The EPA is conducting a comprehensive research study on the potential adverse effects that hydraulic fracturing may have on water quality and public health. It is possible that resulting federal, state and local laws and regulations might be imposed on fracturing activities. The potential adoption of federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and gas wells. A decline in the drilling of new wells and related well servicing activities caused by these initiatives could adversely affect our financial position, results of operations and cash flows.
In addition, our business depends on the demand for land drilling and production services from the oil and gas industry and, therefore, is affected by tax, environmental and other laws relating to the oil and gas industry generally, by changes in those laws and by changes in related administrative regulations. It is possible that these laws and regulations may in the future add significantly to our operating costs or those of our
customers,clients, or otherwise directly or indirectly affect our operations.
Among the services we provide, we operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and
legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.
Interstate motor carrier operations are subject to safety requirements prescribed by the U.S. Department of Transportation. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations.
From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
Risk
Federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and natural gas wells that may reduce demand for our drilling and well servicing activities and could adversely affect our financial position, results of operations and cash flows.
Hydraulic fracturing is a commonly used process that involves injection of water, sand, and a minor amount of certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. The federal Energy Policy Act of 2005 amended the Underground Injection Control provisions of the federal Safe Drinking Water Act (SDWA) to exclude certain hydraulic fracturing practices from the definition of "underground injection." The EPA has asserted regulatory authority over certain hydraulic fracturing activities involving diesel fuel and has developed draft guidance relating to such practices. In addition, repeal of the SDWA exclusion of hydraulic fracturing has been advocated by certain advocacy organizations and others in the public. Congress has from time
to time considered legislation to repeal the exemption for hydraulic fracturing from the SDWA, which would have the effect of allowing the EPA to promulgate new regulations and permitting requirements for hydraulic fracturing, and to require the disclosure of the chemical constituents of hydraulic fracturing fluids to a regulatory agency, which would make the information public via the Internet.
Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a study of the potential environmental impacts of hydraulic fracturing, the final results of which are expected in 2014. In addition, in April 2012, the EPA issued the first federal air standards for natural gas wells that are hydraulically fractured, which will require operators to significantly reduce VOC emissions through the use of “green completions” to capture natural gas that would otherwise escape into the air. These new rules address emissions of various pollutants frequently associated with oil and natural gas production and processing activities by, among other things, requiring new or reworked hydraulically-fractured gas wells to control emissions through flaring until 2015, after which reduced emission (or “green”) completions must be used. The rules also establish specific new requirements, which were effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants, and certain other equipment. On September 23, 2013, the EPA published amendments to the rule which would, among other things, provide additional time for recently constructed, modified or reconstructed storage tanks to install emission controls. The EPA is continuing to consider other aspects of the new rules and may propose additional amendments by the end of 2013 or in early 2014. These rules may require a number of modifications to our clients’ and our own operations, including the installation of new equipment to control emissions. Compliance with such rules could result in additional costs for us and our clients, including increased capital expenditures and operating costs, which may adversely impact our cash flows and results of operations.
The EPA is also developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. The U.S. Department of the Interior has also proposed regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing fluid constituents.
In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, that would require, with some exceptions, disclosure of constituents of hydraulic fracturing fluids, or that would impose higher taxes, fees or royalties on natural gas production. Moreover, public debate over hydraulic fracturing and shale gas production has been increasing, and has resulted in delays of well permits in some areas.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, incurred by our clients. The adoption of any federal, state or local laws or the implementation of regulations or ordinances restricting or increasing the costs of hydraulic fracturing could cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our drilling and well servicing activities, any or all of which could adversely affect our financial position, results of operations and cash flows.
Our operations are subject to the risk of cyber attacks that could have a material adverse effect on our consolidated results of operations and consolidated financial condition.
Our information technology systems are subject to possible breaches and other threats that could cause us harm. If our systems for protecting against cyber security risks prove not to be sufficient, we could be adversely affected by, among other things, loss or damage of intellectual property, proprietary information, or customer data; interruption of business operations; or additional costs to prevent, respond to, or mitigate cyber security attacks. These risks could have a material adverse effect on our business, financial condition and result of operations.
Risks Relating to Our Capitalization and Organizational Documents
We do not intend to pay dividends on our common stock in the foreseeable future, and therefore only appreciation of the price of our common stock will provide a return to our shareholders.
We have not paid or declared any dividends on our common stock and currently intend to retain any earnings to fund our working capital needs,
reduce debt and
fund growth opportunities. Any future dividends will be at the discretion of our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and restrictions imposed by the Texas Business Organizations Code and other applicable laws and by our
credit facilities.Revolving Credit Facility and Senior Notes. Our debt arrangements include provisions that generally prohibit us from paying dividends on our capital stock, including our common stock.
We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
Our articles of incorporation authorize us to issue, without the approval of our shareholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.
Provisions in our organizational documents could delay or prevent a change in control of our company even if that change would be beneficial to our shareholders.
The existence of some provisions in our organizational documents could delay or prevent a change in control of our company even if that change would be beneficial to our shareholders. Our articles of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:
provisions regulating the ability of our shareholders to nominate candidates for election as directors or to bring matters for action at annual meetings of our shareholders;
limitations on the ability of our shareholders to call a special meeting and act by written consent;
provisions dividing our board of directors into three classes elected for staggered terms; and
the authorization given to our board of directors to issue and set the terms of preferred stock.
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Item 1B. | Unresolved Staff Comments |
For a description of our significant properties, see “Business—General” and “Business—Facilities” in Item 1 of this report. We
consider each ofbelieve that we have sufficient properties to conduct our operations and that our significant properties
to beare suitable for
itstheir intended use.
Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including
workers’workers' compensation claims and employment-related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition or results of operations.
Item 4. Mine Safety Disclosures
Not applicable.
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Item 5. | Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities |
As of February 4, 2011, 54,243,452January 30, 2014, 62,537,694 shares of our common stock were outstanding, held by 515383 shareholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock. Our common stock trades on the NYSE AmexNew York Stock Exchange under the symbol “PDC.“PES.” The following table sets forth, for each of the periods indicated, the high and low sales prices per share on the NYSE Amex: | | | | | | | | |
| | | Low | | | High | |
Fiscal Year Ended December 31, 2010: | | | | | | | | |
First Quarter | | $ | 6.89 | | | $ | 9.79 | |
Second Quarter | | | 5.24 | | | | 7.92 | |
Third Quarter | | | 5.40 | | | | 6.90 | |
Fourth Quarter | | | 6.04 | | | | 9.03 | |
| | |
Fiscal Year Ended December 31, 2009: | | | | | | | | |
First Quarter | | $ | 3.28 | | | $ | 6.70 | |
Second Quarter | | | 3.46 | | | | 6.88 | |
Third Quarter | | | 3.96 | | | | 7.34 | |
Fourth Quarter | | | 6.00 | | | | 8.16 | |
| | |
Fiscal Year Ended December 31, 2008: | | | | | | | | |
First Quarter | | $ | 10.59 | | | $ | 16.70 | |
Second Quarter | | | 15.29 | | | | 20.64 | |
Third Quarter | | | 12.49 | | | | 18.82 | |
Fourth Quarter | | | 4.85 | | | | 13.09 | |
share:
|
| | | | | | | |
| | Low | | High |
| Fiscal year ended December 31, 2013 | | | |
| First Quarter | $ | 7.16 |
| | $ | 9.88 |
|
| Second Quarter | 6.53 |
| | 8.50 |
|
| Third Quarter | 6.50 |
| | 7.74 |
|
| Fourth Quarter | 7.05 |
| | 8.74 |
|
| Fiscal year ended December 31, 2012 | | | |
| First Quarter | $ | 8.44 |
| | $ | 10.35 |
|
| Second Quarter | 6.54 |
| | 8.92 |
|
| Third Quarter | 6.82 |
| | 9.14 |
|
| Fourth Quarter | 6.02 |
| | 7.77 |
|
The last reported sales price for our common stock on the NYSE AmexNew York Stock Exchange on February 4, 2011January 30, 2014 was $9.56$8.44 per share. We have not paid or declared any dividends on our common stock and currently intend to retain earnings to fund our working capital needs and growth opportunities. Any future dividends will be at the discretion of our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and the restrictions
imposed by the Texas
Business Organizations Code and other applicable laws and our
credit facilities then impose.Revolving Credit Facility and Senior Notes. Our debt arrangements include provisions that generally prohibit us from paying dividends, other than dividends on our preferred stock. We currently have no preferred stock outstanding.
No shares
We did not make any unregistered sales of our common stock were purchased by or on behalf of our company or any affiliated purchaserequity securities during the quarter ended December 31, 2010.2013
. The following table provides information relating to our repurchase of common shares during the quarter ended December 31, 2013: |
| | | | | | | | | | | | |
| Period | Total Number of Shares Purchased (1) | | Average Price Paid per Share (2) | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs |
| October 1—October 31 | 104 |
| | $ | 7.66 |
| | — |
| | — |
|
| November 1—November 30 | — |
| | $ | — |
| | — |
| | — |
|
| December 1—December 31 | 317 |
| | $ | 7.41 |
| | — |
| | — |
|
| Total | 421 |
| | $ | 7.47 |
| | — |
| | — |
|
| |
| (1) | The shares indicated consist of shares of our common stock tendered by employees to the Company during the three months ended December 31, 2013, to satisfy the employees’ tax withholding obligations in connection with the vesting of restricted stock unit awards, which we repurchased based on the fair market value on the date the relevant transaction occurred. |
| |
| (2) | The calculation of the average price paid per share does not give effect to any fees, commissions or other costs associated with the repurchase of such shares. |
The following graph compares, for the periods from December 31, 20052008 to December 31, 2010,2013, the cumulative total shareholder return on our common stock with the cumulative total return on the companies that comprise the AMEXNYSE Composite Index and a peer group index that includes five companies that provide contract drilling services and / and/or production services. The companies that comprise the peer group index are Patterson-UTI Energy, Inc., Nabors Industries Ltd., Bronco Drilling Company,Basic Energy Services, Inc., Precision Drilling Trust and Key Energy Services.
The comparison assumes that $100 was invested on December 31, 20052008 in our common stock, the companies that compose the AMEXNYSE Composite Index and the companies that compose the peer group index, and further assumes all dividends were reinvested.
| |
Item 6. | Selected Financial Data |
The following information derives from our audited financial statements.
YouThis information should
review this informationbe reviewed in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this report and the
historical financial statements and related notes this report contains.
The acquisitions of WEDGE and Competition, effective March 1, 2008, and the change in our fiscal year end, resulting in a nine month fiscal year ended December 31, 2007, affect the comparability from period to period of our historical results. | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Nine months
Ended
December 31,
2007 | | | Year
Ended
March 31,
2007 | |
| | | 2010(1) | | | 2009(1) | | | 2008(1)(2) | | | |
| | | (In thousands, except per share amounts) | |
Statement of Operations Data: | | | | | | | | | | | | | | | | | | | | |
Revenues | | $ | 487,210 | | | $ | 325,537 | | | $ | 610,884 | | | $ | 313,884 | | | $ | 416,178 | |
Income (loss) from operations | | | (18,572 | ) | | | (31,840 | ) | | | (43,954 | ) | | | 55,260 | | | | 126,976 | |
Income (loss) before income taxes | | | (47,558 | ) | | | (40,172 | ) | | | (56,688 | ) | | | 57,774 | | | | 130,789 | |
Net earnings (loss) applicable to common stockholders | | | (33,261 | ) | | | (23,215 | ) | | | (62,745 | ) | | | 39,645 | | | | 84,180 | |
Earnings (loss) per common share-basic | | $ | (0.62 | ) | | $ | (0.46 | ) | | $ | (1.26 | ) | | $ | 0.80 | | | $ | 1.70 | |
Earnings (loss) per common share-diluted | | $ | (0.62 | ) | | $ | (0.46 | ) | | $ | (1.26 | ) | | $ | 0.79 | | | $ | 1.68 | |
| | | | | |
Other Financial Data: | | | | | | | | | | | | | | | | | | | | |
Net cash provided by operating activities | | $ | 98,351 | | | $ | 123,313 | | | $ | 186,635 | | | $ | 115,455 | | | $ | 131,530 | |
Net cash used in investing activities | | | (129,481 | ) | | | (113,909 | ) | | | (505,615 | ) | | | (123,858 | ) | | | (137,960 | ) |
Net cash provided by financing activities | | | 12,762 | | | | 4,154 | | | | 269,098 | | | | 161 | | | | 201 | |
Capital expenditures | | | 135,151 | | | | 110,453 | | | | 148,096 | | | | 128,038 | | | | 147,230 | |
| | | | | | | | | | | | | | | | | | | | |
| | | As of December 31, | | | As of
March 31,
2007 | |
| | | 2010(1) | | | 2009(1) | | | 2008(1) | | | 2007 | | |
| | | (In thousands) | |
Balance Sheet Data: | | | | | | | | | | | | | | | | | | | | |
Working capital | | $ | 76,142 | | | $ | 90,336 | | | $ | 64,372 | | | $ | 99,807 | | | $ | 124,089 | |
Property and equipment, net | | | 655,508 | | | | 637,022 | | | | 627,562 | | | | 417,022 | | | | 342,901 | |
Long-term debt and capital lease obligations, excluding current installments | | | 279,530 | | | | 258,073 | | | | 262,115 | | | | — | | | | — | |
Shareholders’ equity | | | 396,333 | | | | 421,448 | | | | 414,118 | | | | 471,072 | | | | 428,109 | |
Total assets | | | 841,343 | | | | 824,955 | | | | 824,479 | | | | 560,212 | | | | 501,495 | |
|
| | | | | | | | | | | | | | | | | | | |
| | Year ended December 31, |
| | 2013 (1) | | 2012 | | 2011 | | 2010 | | 2009 |
| | (In thousands, except per share amounts) |
| Statement of Operations Data: | | | | | | | | | |
| Revenues | $ | 960,186 |
| | $ | 919,443 |
| | $ | 715,941 |
| | $ | 487,210 |
| | $ | 325,537 |
|
| Income (loss) from operations | (6,229 | ) | | 81,811 |
| | 57,458 |
| | (18,572 | ) | | (31,840 | ) |
| Income (loss) before income taxes | (55,778 | ) | | 46,386 |
| | 20,833 |
| | (47,558 | ) | | (40,172 | ) |
| Net earnings (loss) applicable to common stockholders | (35,932 | ) | | 30,032 |
| | 11,177 |
| | (33,261 | ) | | (23,215 | ) |
| Earnings (loss) per common share-basic | $ | (0.58 | ) | | $ | 0.49 |
| | $ | 0.19 |
| | $ | (0.62 | ) | | $ | (0.46 | ) |
| Earnings (loss) per common share-diluted | $ | (0.58 | ) | | $ | 0.48 |
| | $ | 0.19 |
| | $ | (0.62 | ) | | $ | (0.46 | ) |
| Other Financial Data: | | | | | | | | | |
| Net cash provided by operating activities | $ | 174,580 |
| | $ | 199,366 |
| | $ | 144,879 |
| | $ | 98,351 |
| | $ | 123,313 |
|
| Net cash used in investing activities | (150,676 | ) | | (361,231 | ) | | (307,484 | ) | | (129,481 | ) | | (113,909 | ) |
| Net cash provided by financing activities | (20,252 | ) | | 99,401 |
| | 226,791 |
| | 12,762 |
| | 4,154 |
|
| Capital expenditures | $ | 125,420 |
| | 379,272 |
| | 237,787 |
| | 135,151 |
| | 110,453 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | As of December 31, |
| | 2013 | | 2012 | | 2011 | | 2010 | | 2009 |
| | (In thousands) |
| Balance Sheet Data: | | | | | | | | | |
| Working capital | $ | 118,547 |
| | $ | 62,236 |
| | $ | 129,932 |
| | $ | 76,142 |
| | $ | 90,336 |
|
| Property and equipment, net | 937,657 |
| | 1,014,340 |
| | 793,956 |
| | 655,508 |
| | 637,022 |
|
| Long-term debt and capital lease obligations, excluding current installments | 499,666 |
| | 518,725 |
| | 418,728 |
| | 279,530 |
| | 258,073 |
|
| Shareholders’ equity | 518,433 |
| | 547,680 |
| | 510,445 |
| | 396,333 |
| | 421,448 |
|
| Total assets | 1,229,623 |
| | 1,339,776 |
| | 1,172,754 |
| | 841,343 |
| | 824,955 |
|
| |
| (1) | The statement of operations data and other financial data for the years ended December 31, 2010, 2009 and 2008 and the balance sheet data as of December 31, 2010, 2009 and 2008 include the impact of the acquisitions of WEDGE and Competition, both of which occurred on March 1, 2008. See Note 2 to Consolidated Financial Statements, included in Part II, Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K. |
(2) | The statement of operations data and other financial data for the year ended December 31, 20082013 reflect the impact of a goodwill impairment charge of $118.6$41.7 million and an intangible asset impairment charge of $52.8$3.1 million. See Note 1 to Consolidated Financial Statements, included in Part II, Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.
|
| |
Item 7.7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Statements we make in the following discussion that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends,
the continued strength or weaknesslevels and volatility of
the contract land drilling industry in the geographic areas in which we operate,oil and gas prices, decisions about
onshore exploration and development projects to be made by oil and gas exploration and production companies,
economic cycles and their impact on capital markets and liquidity, the continued demand for drilling services or production services in the geographic areas where we operate, the highly competitive nature of our business,
theour future financial performance, including availability, terms and deployment of capital,
future compliance with covenants under our senior secured revolving credit facility and our senior notes, the
supply of marketable drilling rigs, well servicing rigs, coiled tubing and wireline units within the industry, changes in technology and improvements in our competitors' equipment, the continued availability of drilling rig, well servicing rig, coiled tubing and wireline unit components, the continued availability of qualified personnel,
the success or failure of our acquisition strategy, including our ability to finance acquisitions, manage growth and effectively integrate acquisitions, and changes in, or our failure or inability to comply with,
governmentgovernmental regulations, including those relating to the environment. We have discussed many of these factors in more detail elsewhere in this report, including under the headings “Special Note Regarding Forward-Looking Statements” in the Introductory Note to Part I and “Risk Factors” in Item 1A. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. All forward-looking statements speak only as
of the date on which they are made and we undertake no
dutyobligation to
publicly update or revise any forward-looking
statements.statements whether as a result of new information, future events or otherwise. We advise our shareholders that they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.
Pioneer Energy Services (formerly called "Pioneer Drilling CompanyCompany") was incorporated under the laws of the State of Texas in 1979 as the successor to a business that had been operating since 1968. Since September 1999, we have significantly expanded our drilling rig fleet through acquisitions and through the construction of rigs from new and used components. In March 2008, we acquired two production services companies which significantly expanded our service offerings to include well servicing, wireline services and fishing and rental services. We have continued to invest in the growth of all our service offerings through acquisitions and organic growth. On December 31, 2011, we acquired the coiled tubing services business of Go-Coil, L.L.C. ("Go-Coil") to expand our existing production services offerings.
In 2012, we changed our company name from "Pioneer Drilling Company" to "Pioneer Energy Services Corp." Our common stock trades on the New York Stock Exchange under the ticker symbol "PES." Our new name reflects our strategy to expand our service offerings beyond drilling services, which has been our core, legacy business.Pioneer Energy Services provides drilling services and production services to a diverse group of independent and majorlarge oil and gas exploration and production companies throughout much of the onshore oil and gas producing regions of the United States and internationally in Colombia. Pioneer Drilling Company was incorporated under the laws of the State of Texas in 1979 as the successor to a business that had been operating since 1968. Our business has grown through acquisitionsWe also provide coiled tubing and through organic growth. Since September 1999, we have significantly expanded our drilling rig fleet by adding 35 rigs through acquisitions and by adding 31 rigs through the construction of rigs from new and used components. On March 1, 2008, we significantly expanded our service offerings when we acquired the production services businesses of WEDGE Group Incorporated (“WEDGE”) for $314.7 million and Prairie Investors d/b/a Competition Wireline (“Competition”) for $30.0 million, which provide well services, wireline services and fishing and rental services. We fundedoffshore in the WEDGE acquisition primarily with $311.5 millionGulf of borrowings under our senior secured revolving credit facility.Mexico. Drilling services and production services are fundamental to establishing and maintaining the flow of oil and natural gas throughout the productive life of a well site and enable us to meet multiple needs of our customers.clients.
We currently conduct our operations through two operating segments: our Drilling Services DivisionSegment and our Production Services Division.Segment. The following is a description of these two operating segments. Financial information about our operating segments is included in Note 11, Segment Information, of the Notes to Consolidated Financial Statements, included in Part II, Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.10-K | • | | Drilling Services Division—Our Drilling Services Division provides contract land drilling services with its fleet of 71 drilling rigs in the following locations:
|
. Drilling Services Segment—Our Drilling Services Segment provides contract land drilling services to a diverse group of oil and gas exploration and production companies with its fleet of 62 drilling rigs which are currently assigned to the following divisions:
|
| | | |
Drilling Division Locations | | Rig Count | |
South Texas | | 14 | 19 |
|
EastWest Texas
| | 18 | 13 |
|
West Texas
North Dakota | | 11 | 3 |
|
North Dakota
| | | 9 | |
North Texas
| | | 3 | |
Utah | | | 3 | |
Oklahoma
| | | 6 | |
Appalachia
| | | 7 |
|
Colombia
Appalachia | | 4 |
|
| Colombia | | 8 |
|
| | 62 |
|
As
In early 2011, we began construction of February 4, 2011, 48 drilling rigs are operating under drilling contracts. We have 17ten new-build AC drilling rigs that are idle and sixfit for purpose for domestic shale plays, based on term contracts. We deployed seven of these new-build drilling rigs have been placedduring 2012, and deployed the final three in storage or “cold stacked” inearly 2013. All of our Oklahoma drilling division due to low demand fornew-build drilling rigs are currently operating in that region. We are actively marketing all our idleshale or unconventional plays under long-term drilling rigs both domestically and internationally in Latin America. contracts.
During the second quarter of 2009,2013, we established our Appalachia drilling division location and now have seven drilling rigs operating in the Marcellus Shale. In early 2011, we established our West Texas drilling division location with threesold two mechanical drilling rigs that were previously includedidle in our East Texas division, for which we recognized an associated gain of approximately $0.8 million. In September 2013, we decided to sell eight of our mechanical drilling division location. Onerigs, for which we recognized an impairment charge of $9.2 million dollars during the third quarter. All eight drilling rigs were classified as held for sale at September 30, 2013 and were sold in late October 2013. We did not incur any additional gain or loss upon the sale of these rigs.
As of December 31, 2013, 50 of our 62 drilling rigs has begunare earning revenues under drilling in the Permian Basincontracts, 39 of which are under term contracts, and we are actively marketing all of our idle drilling rigs. All eight of our drilling rigs in Colombia are currently under term contracts that extend through the end of 2014, seven of which are currently working. The remaining rig will begin working under its term contract after it is upgraded from 1,000 horsepower to 1,500 horsepower, which we expect will be completed by the remaining two rigs to begin operations in late February 2011. end of the first quarter of 2014.
In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with
customers.existing or potential clients. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, and the anticipated duration of the work to be performed.
| • | | Production Services Division—Our Production Services Division
Production Services Segment—Our Production Services Segment provides a range of services to oil and gas exploration and production companies, including well services, wireline services, and fishing and rental services. Our production services operations are managed through locations concentrated in the major United States onshore oil and gas producing regions in the Gulf Coast, Mid-Continent, Rocky Mountain and Appalachian states. We provide our services to a diverse group of oil and gas exploration and production companies. The primary production services we offer are the following:
|
Well Services. Existing and newly-drilled wells require a range of services to exploration and production companies, including well servicing, wireline services, coiled tubing services, and fishing and rental services. Our production services operations are concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore. We provide our services to a diverse group of oil and gas exploration and production companies. The primary production services we offer are the following:
Well Servicing. A range of services are required in order to establish production in newly-drilled wells and to maintain production over theirthe useful lives.lives of active wells. We use our premium well serviceservicing rig fleet to provide these requirednecessary services, including the completion of newly-drilled wells, maintenance of existing wells,and workover of existing wells, completion of newly-drilledactive wells, and plugging and abandonment of wells at the end of their useful lives. We acquired one well service rig in early 2011, resulting in a total As of 75 well service rigs in nine locations as of February 4, 2011. Our well service rig fleet consists of seventyDecember 31, 2013, we operate ninety-nine 550 horsepower rigs fourand ten 600 horsepower rigs through 11 locations, mostly in the Gulf Coast and one 400 horsepower rig, with an average age of 3.4 years. All our well serviceArkLaTex regions, though we also have 14 rigs are currently operating or are being actively marketed, with January 2011 utilization of approximately 88%. We plan to add another five well service rigs to our fleet by mid-2011.in North Dakota.
Wireline Services. In order for oil and gas exploration and production companies to better understand the reservoirs they are drilling or producing, they require logging services to accurately characterize reservoir rocks and fluids. WhenTo complete a producing well, is completed, they also must perforate the production casing must be perforated to establish a flow path between the reservoir and the wellbore. We use our fleet of wireline units to provide these important logging and perforating services. We provide both open and cased-hole logging services, including the latest pulsed-neutron technology. In addition, we provide services which allow oil and gas exploration and production companies to evaluate the integrity of wellbore casing, recover pipe, or install bridge plugs. We acquired 21 As of December 31, 2013, we operate through 24 locations with a fleet of 119 wireline units.
Coiled Tubing Services. Coiled tubing is an important element of the well servicing industry that allows operators to continue production during service operations without shutting in the well, thereby reducing the risk of formation damage. Coiled tubing services involve the use of a continuous metal pipe spooled on a large reel for oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, formation stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is also used for a number of horizontal well applications such as milling temporary plugs between frac stages. As of December 31, 2013, our coiled tubing business consists of nine onshore and four offshore coiled tubing units during 2010which are currently deployed through three locations in Texas and two additional wireline units in early 2011, resulting in a total of 86 wireline units in 22 locations as of February 4, 2011. We plan to add another 12 wireline units by mid-2011.Louisiana.
Fishing and Rental Services. During drilling operations, oil and gas exploration and production companies frequently rent unique equipment such as power swivels, foam circulating units, blow-out preventers, air drilling equipment, pumps, tanks, pipe, tubing and fishing tools. We provide rental services out of fourthree locations in Texas and Oklahoma. As of December 31, 20102013 our fishing and rental tools have a gross book value of $13.5 million.$17.3 million.
Pioneer Energy Services' corporate office is located at 1250 NE Loop 410, Suite 1000, San Antonio, Texas 78209. Our phone number is (855) 884-0575 and our website address is www.pioneeres.com. We make available free of charge though our website our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with the Securities and Exchange Commission (SEC). Information on our website is not incorporated into this report or otherwise made part of this report.
Market Conditions in Our Industry
Demand for oilfield services offered by our industry is a function of our customers’clients’ willingness to make operating expenditures and capital expenditures to explore for, develop and produce hydrocarbons, which in turn is affected by current and expected levels of oil and natural gas prices. From 2004 through 2008, domestic exploration and production spending increased as oil and natural gas prices increased. Since late 2008 and into late 2009, there has beenwas substantial volatility and a decline in oil and natural gas prices due to the downturn in the global economic environment. In response, our customersclients curtailed their drilling programs
and reduced their production activities, particularly in natural gas producing regions, which has resulted in a decrease in demand and revenue rates for certain of our drilling rigs and production services equipment. Additionally, there was uncertainty in the capital markets and access to financing was limited. These conditions adversely affected our business environment. For additional information concerning the effects of the volatility in oil and gas prices and uncertainty in capital markets, see Item 1A—“Risk Factors” in Part I of this Annual Report on Form 10-K. With generally increasing oil prices in 2010 and natural gas prices through 2010,2011, exploration and production companies modestly increased their exploration and production spending for 2010 and industry rigequipment utilization and revenue rates improved, particularly in oil-producing regions and in certain shale regions. We expect continuedDuring 2012, modest increases in exploration and production spending for 2011, which we expect will resultresulted in modest increases in industry rigequipment utilization and revenue rates in 2011,during 2012, as compared to 2010.On February 4, 2011,2011. Despite generally increasing oil prices during 2013, industry equipment utilization levels have been slightly lower than industry levels during 2012, which is partially due to the spot price foradvancements in technology and efficiency of drilling rigs. In addition, excess natural gas production in the U.S. shale regions continues to depress natural gas prices. If oil and natural gas prices decline, then industry equipment utilization and revenue rates could decrease domestically and in Colombia.
Colombia has experienced significant growth in oil production since 2008 largely due to the infusion of capital by international exploration and production companies as a result of the country's improved regulation and security. Historically, Colombian oil prices have generally trended in line with West Texas Intermediate crude(WTI) oil was $89.03,prices. However, fluctuations in oil prices have a less significant impact on demand for drilling and production services in Colombia as compared to the spot priceimpact on demand in North America. Demand for Henry Hub natural gas was $4.47drilling and production services in Colombia is largely dependent upon the Baker Hughes land rig count was 1,696, a 33% increase from 1,280 on February 5, 2010. national oil company's long-term exploration and production programs.
The average weeklytrends in spot prices of West Texas IntermediateWTI crude oil and Henry Hub natural gas, and the average weeklyresulting trends in domestic land rig count per thecounts (per Baker Hughes land rig count,Hughes) and the average monthly domestic well serviceservicing rig count for eachcounts (per Guiberson/Association of Energy Service Companies) over the last five years were: | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | | | 2007 | | | 2006 | |
Oil (West Texas Intermediate) | | $ | 79.39 | | | $ | 61.81 | | | $ | 99.86 | | | $ | 72.71 | | | $ | 66.28 | |
Natural Gas (Henry Hub) | | $ | 4.35 | | | $ | 3.85 | | | $ | 8.81 | | | $ | 6.90 | | | $ | 6.66 | |
U.S. Land Rig Count | | | 1,493 | | | | 1,035 | | | | 1,792 | | | | 1,670 | | | | 1,537 | |
U.S. Well Service Rig Count | | | 1,854 | | | | 1,735 | | | | 2,514 | | | | 2,388 | | | | 2,364 | |
As representedare illustrated in the tablegraphs below.
As shown in the charts above, increasesthe trends in industry rig counts are influenced by fluctuations in oil and natural gas prices, from 2004 to late 2008 resulted in corresponding increases inwhich affect the U.S. land rig countslevels of capital and U.S. well service rig counts, while declines in prices from late 2008 to late 2009 led to decreases in the U.S. land rig counts and U.S. well service rig counts. Since late 2009, increases in oil and natural gas prices have caused modest increases in exploration and production spending and the corresponding increases in drilling and well services activities is reflectedoperating expenditures made by increases in the U.S. land rig counts and the U.S. well service rig counts in 2010.our clients.
Our business is influenced substantially by both operating and capital expenditures by exploration and production companies. Exploration and production spending is generally categorized as either a capital expenditure or operating expenditure. Capital expenditures by oil and gas exploration and production companies tend to be relatively sensitive to volatility in oil or natural gas prices because project decisions are tied to a return on investment spanning a number of years. As such, capital expenditure economics often require the use of commodity price forecasts which may prove inaccurate in the amount of time required to plan and execute a capital expenditure project (such as the drilling of a deep well). When commodity prices are depressed for long periods of time, capital expenditure projects are routinely deferred until prices return to an acceptable level. In contrast, both mandatory and discretionary operating expenditures are more stable than capital expenditures for exploration.exploration as these expenditures are less sensitive to commodity price volatility. Mandatory operating expenditure
projects involve activities that cannot be avoided in the short term, such as regulatory compliance, safety, contractual obligations and certain projects to maintain the well and related infrastructure in operating condition. Discretionary operating expenditure projects may not be critical to the short-term viability of a lease or field but these projectsand are less sensitive to commodity price volatility as compared to capital expenditures for exploration. Discretionary operating expenditure work isgenerally evaluated according to a simple short-term payout criterion whichthat is far less dependent on commodity price forecasts.forecasts
. Because existing oil and natural gas wells require ongoing spending to maintain production, expenditures by exploration and production companies for the maintenance of existing wells are relatively stable and predictable. In contrast, capital expenditures by exploration and production companies for exploration and drilling are more directly influenced by current and expected oil and natural gas prices and generally reflect the volatility of commodity prices. Technological advancements and trends in our industry also affect the demand for certain types of equipment. During 2013, the demand for traditional drilling rigs in vertical markets has softened due to increased demand for drilling rigs that are able to drill horizontally. In addition, oil and gas exploration and production companies have increased the use of "pad drilling" in recent years whereby a series of horizontal wells are drilled in succession by a walking or skidding drilling rig at a single pad-site location. Pad drilling has improved the productivity of exploration and production activities which could reduce the demand for drilling rigs, particularly those that do not have the ability to walk or skid and to drill horizontal wells.
For additional information concerning the effects of the volatility in oil and gas prices and the effects of technological advancements and trends, see Item 1A – “Risk Factors” in Part I of this Annual Report on Form 10-K.
Liquidity and Capital Resources
Sources of Capital Resources
Our principal liquidity requirements have been for working capital needs, debt service, capital expenditures and selective acquisitions. Our principal sources of liquidity consist of: (i)of cash and cash equivalents (which equaled $22.0$27.4 million as of December 31, 2010); (ii)2013), cash generated from operations;operations and (iii) the unused portion of our senior secured revolving credit facility (the “Revolving Credit Facility”).
In July 2011, we obtained $94.3 million in net proceeds from the sale of 6,900,000 shares of our common stock at $14.50 per share, less underwriters’ commissions and other offering costs, pursuant to a public offering under the shelf registration statement which we filed in July 2009. The proceeds from this offering were used to pay down the debt balance outstanding under our Revolving Credit Facility and to fund our new-build drilling rig program. In May 2012, we filed a registration statement that permits us to sell equity or debt in one or more offerings up to a total dollar amount of $300 million. As of December 31, 2013, the entire $300 million under the shelf registration statement is available for equity or debt offerings. In the future, we may consider equity and/or debt offerings, as appropriate, to meet our liquidity needs.
On March 11, 2010, we issued $250 million of senior notes with a coupon interest rate of 9.875% that are due in 2018 (the "2010 Senior Notes"). We received $234.8 million of net proceeds from the issuance of the 2010 Senior Notes that were used to repay a portion of the borrowings outstanding under our Revolving Credit Facility. On November 21, 2011, we issued an additional $175 million of senior notes (the "2011 Senior Notes") with the same terms and conditions as the 2010 Senior Notes. We received $172.7 million of net proceeds from the issuance of the 2011 Senior Notes, a portion of which were used to fund the acquisition of Go-Coil in December 2011.
Our Revolving Credit Facility provides for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-line loans, of up to an aggregate principal amount of $225$250 million, all of which matures on August 31, 2012. We made a $12.8 million principal payment after June 30, 2016. As of December 31, 2010, which resulted in a $25.02013, we had $80.0 million outstanding balance under our Revolving Credit Facility and $9.2$14.0 million in committed letters of credit, at February 4, 2011. Therefore, ourwhich resulted in borrowing availability of $156.0 million under our Revolving Credit Facility was $190.8 million as of February 4, 2011.Facility. There are no limitations on our ability to access the full borrowing availability under the Revolving Credit Facility other than maintaining compliance with the covenants in the Revolving Credit Facility. Additional information regarding these covenants is provided in theDebt Requirements section below. Borrowings under the Revolving Credit Facility are available for selective acquisitions, working capital and other general corporate purposes.
We
presentlycurrently expect that cash and cash equivalents, cash generated from operations and available borrowings under our Revolving Credit Facility are adequate to cover our liquidity requirements for at least the next 12 months.
On March 11, 2010, we issued $250 million of 9.875% unregistered senior notes due 2018 (the “Senior Notes”), and received $234.8 million net proceeds, after deducting the original issue discount, underwriters’ fees and other debt offering costs, which were used to reduce the outstanding debt balance under our Revolving Credit Facility. The Senior Notes will mature on March 15, 2018 with interest due semi-annually in arrears on March 15 and September 15 of each year, commencing on September 15, 2010. We have the option to redeem the Senior Notes, in whole or in part, at any time on or after March 15, 2014 in each case at the redemption price specified in the Indenture dated March 11, 2010 (the “Indenture”) together with any accrued and unpaid interest to the date of redemption. Prior to March 15, 2014, we may also redeem the Senior Notes, in whole or in part, at a “make-whole” redemption price specified in the Indenture, together with any accrued and unpaid interest to the date of redemption. In addition, prior to March 15, 2013, we may, on one or more occasions, redeem up to 35% of the aggregate principal amount of the Senior Notes at a redemption price of 109.875% of the principal amount, plus any accrued and unpaid interest to the redemption date, with the net proceeds of certain equity offerings, if at least 65% of the aggregate principal amount of the Senior Notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing of the equity offering. In accordance with a registration rights agreement with the holders of our Senior Notes, we filed an exchange offer registration statement on Form S-4 with the Securities and Exchange Commission that became effective on September 2, 2010. This exchange offer registration statement enabled the holders of our Senior Notes to exchange their Senior Notes for publicly registered notes with substantially identical terms. References to the “Senior Notes” herein include the Senior Notes issued in the exchange offer.
In July 2009, we filed a shelf registration statement that permits us to sell equity or debt in one or more offerings up to a total dollar amount of $300 million. In November 2009, we obtained $24.0 million in net proceeds when we sold 3,820,000 shares of our common stock at $6.75 per share, less underwriters’ commissions, pursuant to a public offering under the $300 million shelf registration statement. The remaining availability under the $300 million shelf registration statement for equity or debt offerings is $274.2 million as of February 4, 2011. In the future, we may consider equity or debt offerings, as appropriate, to meet our liquidity needs.
At December 31, 2010, we held $15.9 million (par value) of ARPSs, which were variable-rate preferred securities and had a long-term maturity with the interest rate being reset through “Dutch auctions” that were held every seven days. The ARPSs had historically traded at par because of the frequent interest rate resets and because they were callable at par at the option of the issuer. Interest was paid at the end of each auction period. Our ARPSs were AAA/Aaa rated securities, collateralized by municipal bonds and backed by assets that were equal to or greater than 200% of the liquidation preference. Until February 2008, the auction rate securities market was highly liquid. Beginning mid-February 2008, we experienced several “failed” auctions, meaning that there was not enough demand to sell all of the securities that holders desired to sell at auction. The immediate effect of a failed auction was that such holders could not sell the securities at auction and the interest rate on the security reset to a maximum auction rate. We continued to receive interest payments on our ARPSs in accordance with their terms.
On January 19, 2011, we entered into an agreement with a financial institution to sell the ARPSs for $12.6 million, which represents 79% of the par value, plus accrued interest. Under the agreement, we retained the unilateral right for a period ending January 7, 2013 to: (a) repurchase all the ARPSs at the $12.6 million price at which they were initially sold to the financial institution; and (b) if not repurchased, receive additional proceeds from the financial institution upon redemption of the ARPSs by the original issuer.
Uses of Capital Resources
For the years ended December 31, 20102013 and 2009,2012, our primary uses of capital resources were for property and equipment additions thatwhich consisted of the following (amounts in thousands): | | | | | | | | |
| | | Years ended
December 31, | |
| | | 2010 | | | 2009 | |
Drilling Services Division: | | | | | | | | |
Routine | | $ | 17,441 | | | $ | 14,655 | |
Discretionary | | | 88,201 | | | | 70,502 | |
New-builds and acquisitions | | | — | | | | 12,046 | |
| | | | | | | | |
Total Drilling Services Division | | | 105,642 | | | | 97,203 | |
Production Services Division: | | | | | | | | |
Routine | | | 6,972 | | | | 5,366 | |
Discretionary | | | 1,202 | | | | 662 | |
New-builds and acquisitions | | | 17,187 | | | | 11,481 | |
| | | | | | | | |
Total Production Services Division | | | 25,361 | | | | 17,509 | |
| | | | | | | | |
Net cash used for purchases of property and equipment | | | 131,003 | | | | 114,712 | |
Net impact of accruals | | | 4,148 | | | | (4,259 | ) |
| | | | | | | | |
Total Capital Expenditures | | $ | 135,151 | | | $ | 110,453 | |
| | | | | | | | |
We capitalized $0.5 million and $0.3 million of interest costs in property and equipment during the years ended December 31, 2010 and 2009, respectively.
|
| | | | | | | |
| | Year ended December 31, |
| | 2013 | | 2012 |
| Drilling Services Segment: | | | |
| Routine | $ | 39,276 |
| | $ | 39,051 |
|
| Discretionary | 35,569 |
| | 56,430 |
|
| Fleet additions | 41,679 |
| | 162,677 |
|
| Total Drilling Services Segment | 116,524 |
| | 258,158 |
|
| Production Services Segment: | | | |
| Routine | 23,053 |
| | 15,311 |
|
| Discretionary | 20,092 |
| | 37,562 |
|
| Fleet additions | 5,687 |
| | 53,293 |
|
| Total Production Services Segment | 48,832 |
| | 106,166 |
|
| Net cash used for purchases of property and equipment | 165,356 |
| | 364,324 |
|
| Net impact of accruals | (39,936 | ) | | 14,948 |
|
| Total Capital Expenditures | $ | 125,420 |
| | $ | 379,272 |
|
Our Drilling Services Division performed significant upgrade projectsSegment incurred $12.3 million and $173.0 million of costs, including accruals for capital expenditures, on 24the construction of our new-build drilling rigs during the years ended December 31, 2013 and 2012, respectively. Additionally, during the year ended December 31, 2010, primarily2013, we performed significant upgrade projects to various rigs in connection with obtaining newour drilling contracts in unconventional plays and Colombia. These projects includedfleet including, among others, the installation of 16 top drives, five iron roughnecks, twofour additional automatic catwalks and 11 walking/skidding systems.two additional walking systems, the upgrade of two drilling rigs to higher horsepower and we upgraded four rigs with higher horsepower mud pumps. During the year ended December 31, 2009,2012, we performed significant upgrade projects on sevento our drilling rigs including, among others, the additioninstallation of 11nine additional automatic catwalks, one additional iron roughneck, one top drivesdrive, the upgrade of three drilling rigs to higher horsepower and we upgraded two rigs with higher horsepower mud pumps. In connection with the construction of our new-build drilling rigs. Alsorigs and other drilling equipment upgrades, we capitalized $0.9 million and $10.2 million of interest costs during the years ended December 31, 2013 and 2012, respectively.
Our Production Services Segment acquired three wireline units and one well servicing rig during the year ended December 31, 2013. During the year ended December 31, 2009,2012, we incurred $13.7 million of rig construction costs to complete construction of a 2000 horsepower drilling rig which was placed into service in June 2009.Our Production Services Division acquired 20 and five15 wireline units, as19 well as auxiliary equipment for well serviceservicing rigs, during the years ended December 31, 2010 and 2009, respectively, which is reflected in the new-builds and acquisitions section of the table above.
three coiled tubing units.
Currently, we expect to spend approximately $140$115 million to $150$125 million on capital expenditures during 2011.2014. We expect the total capital expenditures for 20112014 will be allocated approximately 75%60% for our Drilling Services DivisionSegment and approximately 25%40% for our Production Services Division.Segment. Our planned capital expenditures for the year ending December 31, 20112014 include 14 wireline units and six well service rigs that we expect will go into service during the first half of 2011 and two new-build drillings rigs. We will not begin construction of these new-buildupgrades to certain drilling rigs, unless we have secured long-term contracts.additional production services equipment and routine capital expenditures. Actual capital expenditures may vary depending on the timing of commitments and payments, as well as the level of new-build and other expansion opportunities that meet our strategic and return on capital employed criteria. We expect to fund these the capital expenditures in 2014 from operating cash flow in excess of our working capital and other normal cash flow requirements, and from borrowings under our Revolving Credit Facility, as necessary.requirements.
Our working capital was $76.1$118.5 million at December 31, 2010,2013, compared to $90.3$62.2 million at December 31, 2009.2012. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 2.0 at December 31, 20102013 compared to 2.91.4 at December 31, 2009.2012
. Our operations have historically generated cash flows sufficient to meet our requirements for debt service and normal capital expenditures. However, our working capital requirements could increase during periods when higher percentages of our drilling contracts are turnkey and footage contracts and when new-build rig construction projects are in progress.
With the completion of our
short-term workingnew-build drilling rig program in the first quarter of 2013, we have shifted our near-term focus toward reducing capital
needs could increase.expenditures and using excess cash flows from operations to reduce outstanding debt balances. The changes in the components of our working capital were as follows (amounts in thousands):
| | | | | | | | | | | | |
| | | December 31, 2010 | | | December 31, 2009 | | | Change | |
Cash and cash equivalents | | $ | 22,011 | | | $ | 40,379 | | | $ | (18,368 | ) |
Short-term investments | | | 12,569 | | | | — | | | | 12,569 | |
Receivables: | | | | | | | | | | | | |
Trade, net of allowance for doubtful accounts | | | 61,345 | | | | 26,648 | | | | 34,697 | |
Unbilled receivables | | | 21,423 | | | | 8,586 | | | | 12,837 | |
Insurance recoveries | | | 4,035 | | | | 5,107 | | | | (1,072 | ) |
Income taxes | | | 2,712 | | | | 41,126 | | | | (38,414 | ) |
Deferred income taxes | | | 9,867 | | | | 5,560 | | | | 4,307 | |
Inventory | | | 9,023 | | | | 5,535 | | | | 3,488 | |
Prepaid expenses and other current assets | | | 8,797 | | | | 6,199 | | | | 2,598 | |
| | | | | | | | | | | | |
Current assets | | | 151,782 | | | | 139,140 | | | | 12,642 | |
| | | | | | | | | | | | |
Accounts payable | | | 26,929 | | | | 15,324 | | | | 11,605 | |
Current portion of long-term debt | | | 1,408 | | | | 4,041 | | | | (2,633 | ) |
Prepaid drilling contracts | | | 3,669 | | | | 408 | | | | 3,261 | |
Accrued expenses: | | | | | | | | | | | | |
Payroll and related employee costs | | | 18,057 | | | | 7,740 | | | | 10,317 | |
Insurance premiums and deductibles | | | 8,774 | | | | 8,615 | | | | 159 | |
Insurance claims and settlements | | | 4,035 | | | | 5,042 | | | | (1,007 | ) |
Interest | | | 7,307 | | | | 271 | | | | 7,036 | |
Other | | | 5,461 | | | | 7,363 | | | | (1,902 | ) |
| | | | | | | | | | | | |
Current liabilities | | | 75,640 | | | | 48,804 | | | | 26,836 | |
| | | | | | | | | | | | |
Working capital | | $ | 76,142 | | | $ | 90,336 | | | $ | (14,194 | ) |
| | | | | | | | | | | | |
|
| | | | | | | | | | | |
| | December 31,
2013 | | December 31,
2012 | | Change |
| Cash and cash equivalents | $ | 27,385 |
| | $ | 23,733 |
| | $ | 3,652 |
|
| Receivables: | | | | | |
| Trade, net of allowance for doubtful accounts | 115,908 |
| | 115,070 |
| | 838 |
|
| Unbilled receivables | 49,535 |
| | 35,140 |
| | 14,395 |
|
| Insurance recoveries | 8,607 |
| | 6,518 |
| | 2,089 |
|
| Income taxes and other | 2,310 |
| | 2,116 |
| | 194 |
|
| Deferred income taxes | 13,092 |
| | 11,058 |
| | 2,034 |
|
| Inventory | 13,232 |
| | 12,111 |
| | 1,121 |
|
| Prepaid expenses and other current assets | 9,311 |
| | 13,040 |
| | (3,729 | ) |
| Current assets | 239,380 |
| | 218,786 |
| | 20,594 |
|
| Accounts payable | 43,718 |
| | 83,823 |
| | (40,105 | ) |
| Current portion of long-term debt | 2,847 |
| | 872 |
| | 1,975 |
|
| Deferred revenues | 699 |
| | 3,880 |
| | (3,181 | ) |
| Accrued expenses: | | | | | |
| Payroll and related employee costs | 30,020 |
| | 27,991 |
| | 2,029 |
|
| Insurance premiums and deductibles | 10,940 |
| | 9,708 |
| | 1,232 |
|
| Insurance claims and settlements | 8,607 |
| | 6,348 |
| | 2,259 |
|
| Interest | 12,275 |
| | 12,343 |
| | (68 | ) |
| Other | 11,727 |
| | 11,585 |
| | 142 |
|
| Current liabilities | 120,833 |
| | 156,550 |
| | (35,717 | ) |
| Working capital | $ | 118,547 |
| | $ | 62,236 |
| | $ | 56,311 |
|
The decreaseincrease in cash and cash equivalents wasduring the year ended December 31, 2013 is primarily due to $131.0$174.6 million of cash provided by operating activities and $13.8 million of proceeds from the sale of assets, which was mostly offset by $165.4 million used for purchases of property and equipment offset by cash provided by operations of $98.4and $20.9 million and $12.7 million in proceeds from used to repay debt, borrowings, net of debt repayments and issuance costs,additional borrowings during the year ended December 31, 2010.Short-term investments as of December 31, 2010 represent our ARPS which were classified as available for sale as of December 31, 2010, and were liquidated in January 2011. At December 31, 2009, these investments were classified as long-term investments due to our inability to determine the recovery period for these investments at that time.
year.
The increasesnet increase in our total trade receivables and unbilled receivables as of December 31, 20102013 as compared to December 31, 2009 were due to the increase in revenues of $67.4 million, or 83%, for the quarter ended December 31, 2010 as compared to the quarter ended December 31, 2009, and2012 is primarily due to the timing of the billing and collection cycles for long-term drilling contracts in Colombia.Income taxes receivableColombia, as well as the
increase in consolidated revenues of $10.3 million, or 5%, for the quarter ended December 31, 2013 as compared to the quarter ended December 31, 2012. The increase in both our insurance recoveries receivables and our insurance claims and settlements accrued expenses as of December 31, 2009 primarily related2013 as compared to net operating losses recognized during 2009. We applied our net operating losses against taxable income that we recognized in prior years which resulted in a federal tax refund. Our income taxes receivable decreased at December 31, 2010, as we received a federal income tax refund of $40.6 million2012 is primarily due to an increase in April 2010 primarily related to the carry-backour insurance company's reserve for workers compensation claims in excess of our 2009 net operating losses.deductibles.
The increase in current deferred income taxes as of December 31, 2013 as compared to December 31, 2012is due to thea movement of our deferred tax assets related to net operating losses for our Colombian operations from long-term to current. We nowcurrent, as we expect to realize the deferred tax assetsthem in the short-term due to the increase in our Colombian operations through 2010.short term.
The increase in inventory at as of December 31, 20102013 as compared to December 31, 2009 was primarily2012 is due to the expansion of our operations in Colombia, which accounted for $2.4 millionwireline and coiled tubing operations. Our wireline inventory has increased as activity has increased during the fourth quarter of 2013, as compared to the increase,fourth quarter of 2012, and our coiled tubing inventory has increased with the remaining increase primarily due to therecent expansion of our domestic wirelineoperations to provide services operations during 2010. We maintain inventories of replacement parts and supplies for our drilling rigs operating in Colombia to ensure efficient operations in geographically remote areas. During 2010, we exported our seventh and eighth drilling rigs to Colombia and established an additional inventory level for these two additional rigs.using a larger diameter coiled tubing.
The increasedecrease in prepaid expenses and other current assets at as of December 31, 20102013 as compared to December 31, 20092012 is primarily due to the amortization of deferred mobilization costs relating to drilling contracts for our new-build drilling rigs and other drilling rigs that moved between geographic regions of the United States and Colombia.
The decrease in accounts payable is primarily due to a $39.9 milliondecrease in our accruals for capital expenditures as of December 31, 2013 as compared to December 31, 2012, as we completed construction of three of our new-build drilling rigs during the first quarter of 2013.
The current portion of our long-term debt is primarily related to a short-term financing for insurance premiums with monthly payments due through August 2014.
The decrease in deferred revenues is related to the amortization of deferred mobilization revenues relating to drilling contracts for our new-build drilling rigs and other drilling rigs that moved between geographic regions of the United States and Colombia.
The increase in accrued payroll and employee related costs is primarily due to an increase in deferred mobilization costs for four drilling rigs that began new long-term drilling contracts duringpayroll accruals resulting from more payroll days reflected in the year ended accrued payroll at December 31, 2010. These deferred mobilization costs are being amortized over2013 as compared to December 31, 2012, due to the related contract terms.timing of pay periods.
The increase in
accounts payable at December 31, 2010 as compared to December 31, 2009 is due to the overall increase in the demand for drilling, well services, wireline servicesour accrued insurance premiums and
fishing and rental services during the quarter ended December 31, 2010 as compared to the quarter ended December 31, 2009. Our operating costs increased $37.1 million, or 65%, during the fourth quarter of 2010 as compared to the fourth quarter of 2009. In addition, our capital expenditures accruals increased for the quarter ended December 31, 2010 as compared to the quarter ended December 31, 2009, accounting for $4.1 million of the increase in accounts payable. Both the increase in the demand for our services and the increase in capital expenditures led to an increase in purchases from our vendors.The current portion of long-term debt at December 31, 2010 relates to $1.4 million of debt payments under our subordinated notes payable and other debt that are due within the next year.
Prepaid drilling contracts represent amounts billed for mobilization revenues in excess of revenue recognized for certain drilling contracts. Mobilization billings, and costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contracts. The increase in prepaid drilling contracts at December 31, 2010 as compared to December 31, 2009deductibles is primarily due to an increase in deferred mobilization revenuesour accrual for fourworkers compensation claims and health insurance costs resulting from an increase in our estimated liability for the deductibles under these policies.
The increase in other accrued expenses as of the drilling rigs in Colombia that began new long-term drilling contracts during the year ended December 31, 2010.The2013
as compared to December 31, 2012 is due to an increase in accrued payroll and related employee costs wasproperty tax primarily due to workforce additions and increased accruals forthe movement of drilling assets from lower taxed regions to higher bonuses for 2010, bothtaxed regions, as well as timing of payments, but which arewas mostly offset by a result of higher demand fordecrease in our drilling and production services during the year ended December 31, 2010. Our employee count increased by approximately 850 people, or 50%, as of December 31, 2010, as compared to December 31, 2009.Accrued interest at December 31, 2010 primarily relates to the outstanding debt balance for our Senior Notes, while accrued interest at December 31, 2009sales tax accrual which was primarily related to the outstanding debt balance underconstruction of our Revolving Credit Facility. On March 11, 2010, we issued $250 millionnew-build drilling rigs that were completed in the first quarter of Senior Notes with a coupon interest rate of 9.875%. The Senior Notes were sold with an original issue discount that will result in an effective yield to maturity of approximately 10.677%. The proceeds from the issuance of the Senior Notes were immediately used to make a payment of $234.8 million to reduce the outstanding debt balance under the Revolving Credit Facility.
The Revolving Credit Facility had an interest rate of 3.74% as of December 31, 2009 which was based on the LIBOR rate plus a per annum margin, with interest payments due monthly. The Senior Notes have a higher interest rate as compared to the Revolving Credit Facility, with interest payments due semi-annually, which resulted in an increase in accrued interest as of December 31, 2010.
2013.
Long-term Debt and Other Contractual Obligations
The following table includes allinformation about the amount and timing of our contractual obligations at December 31, 20102013 (amounts in thousands): | | | | | | | | | | | | | | | | | | | | |
| | | Payments Due by Period | |
Contractual Obligations | | Total | | | Less than
1 year | | | 2-3 years | | | 4-5 years | | | More than 5
years | |
Long-term debt | | $ | 290,858 | | | $ | 1,408 | | | $ | 39,450 | | | $ | — | | | $ | 250,000 | |
Interest on long-term debt | | | 188,580 | | | | 26,755 | | | | 50,731 | | | | 49,375 | | | | 61,719 | |
Purchase commitments | | | 11,611 | | | | 11,611 | | | | — | | | | — | | | | — | |
Operating leases | | | 6,527 | | | | 2,408 | | | | 3,369 | | | | 750 | | | | — | |
Restricted cash obligation | | | 1,950 | | | | 650 | | | | 1,300 | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | |
Total | | $ | 499,526 | | | $ | 42,832 | | | $ | 94,850 | | | $ | 50,125 | | | $ | 311,719 | |
| | | | | | | | | | | | | | | | | | | | |
Long-term
|
| | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period |
| Contractual Obligations | Total | | Within 1 Year | | 2 to 3 Years | | 4 to 5 Years | | Beyond 5 Years |
| Debt | $ | 507,927 |
| | $ | 2,847 |
| | $ | 80,080 |
| | $ | 425,000 |
| | $ | — |
|
| Interest on debt | 194,739 |
| | 44,341 |
| | 87,445 |
| | 62,953 |
| | — |
|
| Purchase commitments | 8,781 |
| | 8,781 |
| | — |
| | — |
| | — |
|
| Operating leases | 14,919 |
| | 5,032 |
|
| 5,415 |
|
| 3,106 |
|
| 1,366 |
|
| Other long-term liabilities | 12,266 |
| | 6,172 |
| | 6,094 |
| | — |
| | — |
|
| Total | $ | 738,632 |
| | $ | 67,173 |
| | $ | 179,034 |
| | $ | 491,059 |
| | $ | 1,366 |
|
At December 31, 2013, long-term debt consists of $37.8$425 million outstanding under our Revolving Credit Facility, $250 million face amount outstanding under our Senior Notes, $3.0$80.0 million outstanding under subordinated notes payable to certain employees that are former shareholdersour Revolving Credit Facility and $2.9 million of previously acquired production services businesses, and other debt of $0.1 million.outstanding. The $37.8$80.0 million outstanding under our Revolving Credit Facility is due at maturity on August 31, 2012.June 30, 2016. However, we may make principal payments to reduce the outstanding debt balance prior to maturity when cash and working capital
is sufficient. The $425 million face amount outstanding balance under our Senior Notes haswill mature on March 15, 2018. Our Senior Notes have a carrying value of $240.1$419.6 million as of December 31, 2013, which represents the $250$425.0 million face value net of the $9.9$6.7 million of original issue discount and $1.3 million of original issue premium, net of amortization. The discount is being amortized over the term of the Senior Notesamortization, based on the effective interest method. The Senior Notes will mature on March 15, 2018. Our subordinated notes payable have final maturity dates ranging from January 2011 to April 2013. Interest payment obligations on our Revolving Credit Facility are estimated based on (1) the 4.77%2.9% interest rate that was in effect on February 4, 2011at December 31, 2013, and (2) the outstanding principal balance of $37.8$80.0 million at December 31, 20102013 to be paid at maturity in August 2012.on June 30, 2016. Interest payment obligations on our Senior Notes are calculated based on the coupon interest rate of 9.875% due semi-annually in arrears on March 15 and September 15 of each year, commencing on September 15, 2010, through maturity. Interest payment obligations on our subordinated notes payable are based on interest rates ranging from 5.4% to 14%, with either quarterly or annual payments of principal and interest through maturity.year.
Purchase
obligationscommitments primarily relate to equipment upgrades and purchases of
other new equipment.
Operating leases consist of lease agreements for office space, operating facilities, equipment and personal property.
As
Other long-term liabilities include the net equity tax payable to the Colombian tax authority and long-term incentive compensation which is payable to our employees, generally contingent upon their continued employment through the date of
December 31, 2010, we had restricted cash in the amount of $2.0 million held in an escrow account to be used for future payments in connection with the acquisition of Competition. The former owner of Competition will receive annual installments of $0.7 million payable over the remaining three years from the escrow account.each respective award's payout.
The Revolving Credit Facility contains customary mandatory prepayments in respectfrom the proceeds of certain asset dispositions or debt incurrence and equity issuances, which are applied to reduce outstanding revolving and swing-line loans andletter of credit exposure. There are no limitations on our ability to access the $225
$250 million borrowing capacity under the Revolving Credit Facility other than maintaining compliance with the covenants.covenants under the Revolving Credit Facility. At December 31, 2010,2013, we were in compliance with our financial covenants.covenants under the Revolving Credit Facility. Our total consolidated leverage ratio was 2.72.0 to 1.0, our senior consolidated leverage ratio was 0.4 to 1.0, and our interest coverage ratio was 4.25.3 to 1.0.The financial covenants contained in our Revolving Credit Facility include the following:
A maximum total consolidated leverage ratio that cannot exceed:
5.00exceed 4.00 to 1.00 as of the end of any fiscal quarter ending December 31, 2010 through June 30, 2011;
1.00;4.75 to 1.00 as of the end of the fiscal quarter ending September 30, 2011;
4.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2011;
4.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2012; and
4.00 to 1.00 as of the end of any fiscal quarter ending June 30, 2012 and thereafter.
A maximum senior consolidated leverage ratio, which excludes unsecured and subordinated debt, that cannot exceed:
4.50exceed 2.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2010;
1.00;4.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2011;
4.00 to 1.00 as of the end of the fiscal quarter ending June 30, 2011;
3.75 to 1.00 as of the end of the fiscal quarter ending September 30, 2011;
3.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2011;
3.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2012; and
3.00 to 1.00 as of the end of any fiscal quarter ended June 30, 2012 and thereafter.
A minimum interest coverage ratio that cannot be less than:
2.00than 2.50 to 1.00 as of the end of any fiscal quarter ending December 31, 2010 through December 31, 2011;1.00; and
3.00 to 1.00 as of the end of any fiscal quarter ending March 31, 2012 and thereafter.
If our senior consolidated leverage ratio is greater than 2.252.00 to 1.00 at the end of any fiscal quarter, aour minimum asset coverage ratio that cannot be less than 1.00 to 1.00 for any fiscal quarter ending on or before December 31, 2011, and 1.10 to 1.00 for any fiscal quarter ending March 31, 2012 and thereafter (as provided in the1.00.
The Revolving Credit Facility). If our senior consolidated leverage ratio is greater than 2.25 to 1.00 and our asset coverage ratio is less than 1.00 to 1.00, then borrowings outstandingFacility does not restrict capital expenditures as long as (a) no event of default exists under the Revolving Credit Facility will be limited to the sum of 80% of eligible accounts receivable, 80% of the orderly liquidation value of eligible equipment and 40% of the net book value of certain other fixed assets.
The Revolving Credit Facility restrictsor would result from such capital expenditures, unless (a)(b) after giving effect to such capital expenditure, no event of default would exist under the Revolving Credit Facility andexpenditures there is availability under the Revolving Credit Facility would be equal to or greater than $25
$25 million and (b) if(c) the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter wasis less than 2.00 to 1.00. If the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter is equal to or greater than 2.502.00 to 1.00, such capital expenditure would not cause the sum of allthen capital expenditures are limited to exceed:
$65100 million for the fiscal year 2010; and
$80 million for each fiscal year thereafter.
year. The capital expenditure thresholds for each period noted abovethreshold may be increased by:
the first $25 million of any aggregate equity issuance proceeds received during such period and 25% of any equity issuance proceeds received in excess of $25 million during such period; and
25% of any debt incurrence proceeds received during such period.
In addition,by any unused portion of the capital expenditure threshold up to $30 million can be carried over from the immediate preceding fiscal year.
year up to $30 million.
At December 31, 2010,2013, our senior consolidated leverage ratio was not greater than 2.502.00 to 1.00 and therefore, we were not subject to the capital expenditure threshold restrictions listed above. The Revolving Credit Facility has additional restrictive covenants that, among other things, limit the incurrence of additional debt, investments, liens, dividends, acquisitions, redemptions of capital stock, prepayments of indebtedness, asset dispositions, mergers and consolidations, transactions with affiliates, hedging contracts, sale leasebacks and other matters customarily restricted in such agreements. In addition, the Revolving Credit Facility contains customary events of default, including without limitation, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults to certain other material indebtedness in excess of specified amounts, certain events of bankruptcy and insolvency, judgment defaults in excess of specified amounts, failure of any guaranty or security document supporting the credit agreement and change of control.
Our obligations under the Revolving Credit Facility are secured by substantially all of our domestic assets (including equity interests in Pioneer Global Holdings, Inc. and 65% of the outstanding equity interests of any first-tier foreign subsidiaries owned by Pioneer Global Holdings, Inc., but excluding any equity interest in, and any assets of, Pioneer Services Holdings, LLC) and are guaranteed by certain of our domestic subsidiaries, including Pioneer Global Holdings, Inc. Effective October 1, 2012, Pioneer Coiled Tubing Services, LLC (formerly Go-Coil, L.L.C.) was added as a subsidiary guarantor under the Revolving Credit Facility. Borrowings under the Revolving Credit Facility are available for acquisitions, working capital and other general corporate purposes.
In addition to the financial covenants under our Revolving Credit Facility, the Indenture
Agreement for our Senior Notes contains certain restrictions
generally on our ability to:
repurchase stock or redeem subordinated debt or make other restricted payments;
incur, assume or guarantee additional indebtedness or issue disqualified stock;
create liens on our assets;
enter into sale and leaseback transactions;
pay dividends, engage in loans, or transfer other assets from certain of our subsidiaries;
consolidate with or merge with or into, or sell all or substantially all of our properties to another person;
enter into transactions with affiliates; and
enter into new lines of business.
These covenants are subject to important exceptions and qualifications.
Upon the occurrence of a change of control, holders of the Senior Notes will have the right to require us to purchase all or a portion of the Senior Notes at a price equal to 101% of the principal amount of each Senior Note, together with any accrued and unpaid interest to the date of purchase. Under certain circumstances in connection with asset dispositions, we will be required to use the excess proceeds of asset dispositions to make an offer to purchase the Senior Notes at a price equal to 100% of the principal amount of each Senior Note, together with any accrued and unpaid interest to the date of purchase. Our Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our existing domestic subsidiaries, except for Pioneer Services Holdings, LLC, and by certain of our future domestic subsidiaries.
Effective October 1, 2012, the Indenture was supplemented to add Pioneer Coiled Tubing Services, LLC (formerly Go-Coil, L.L.C.) as a subsidiary guarantor. The subsidiaries that generally operate our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. The non-guarantor subsidiaries do not have any payment obligations under the Senior Notes, the guarantees or the Indenture. In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes.
Our Senior Notes are not subject to any sinking fund requirements. As of December 31, 2010,2013, there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company, and we were in compliance with all covenants pertaining to our Senior Notes.
Results of Operations
Statements of Operations Analysis—Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012
The following table provides information about our operations for the years ended December 31, 2013 and 2012 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information).
|
| | | | | | | |
| | Year ended December 31, |
| | 2013 | | 2012 |
| Drilling Services Segment: | | | |
| Revenues | $ | 528,327 |
| | $ | 498,867 |
|
| Operating costs | 351,630 |
| | 333,846 |
|
| Drilling Services Segment margin | $ | 176,697 |
| | $ | 165,021 |
|
| | | | |
| Average number of drilling rigs | 68.2 |
| | 65.0 |
|
| Utilization rate | 84 | % | | 87 | % |
| Revenue days | 20,977 |
| | 20,728 |
|
| | | | |
| Average revenues per day | $ | 25,186 |
| | $ | 24,067 |
|
| Average operating costs per day | 16,763 |
| | 16,106 |
|
| Drilling Services Segment margin per day | $ | 8,423 |
| | $ | 7,961 |
|
| | | | |
| Production Services Segment: | | | |
| Revenues | $ | 431,859 |
| | $ | 420,576 |
|
| Operating costs | 276,808 |
| | 252,775 |
|
| Production Services Segment margin | $ | 155,051 |
| | $ | 167,801 |
|
| | | | |
| Combined: | | | |
| Revenues | $ | 960,186 |
| | $ | 919,443 |
|
| Operating costs | 628,438 |
| | 586,621 |
|
| Combined margin | $ | 331,748 |
| | $ | 332,822 |
|
| Adjusted EBITDA | $ | 234,742 |
| | $ | 249,283 |
|
Drilling Services Segment margin represents contract drilling revenues less contract drilling operating costs. Production Services Segment margin represents production services revenue less production services operating costs. We believe that Drilling Services Segment margin and Production Services Segment margin are useful measures for evaluating financial performance, although they are not measures of financial performance under U.S. Generally Accepted Accounting Principles (GAAP). However, Drilling Services Segment margin and Production Services Segment margin are common measures of operating performance used by investors, financial analysts, rating agencies and Pioneer’s management. Drilling Services Segment margin and Production Services Segment margin as presented may not be comparable to other similarly titled measures reported by other companies.
Adjusted EBITDA is a financial measure that is not in accordance with GAAP, and should not be considered (a) in isolation of, or as a substitute for, net income (loss), (b) as an indication of cash flows from operating activities or (c) as a measure of liquidity. In addition, Adjusted EBITDA does not represent funds available for discretionary use. We define Adjusted EBITDA as income (loss) before interest income (expense), taxes, depreciation, amortization and any impairments. We use this measure, together with our GAAP financial metrics, to assess our financial performance and evaluate our overall progress towards meeting our long-term financial objectives. We believe that
this non-GAAP financial measure is useful to investors and analysts in allowing for greater transparency of our operating performance and makes it easier to compare our results with those of other companies within our industry. Adjusted EBITDA, as we calculate it, may not be comparable to Adjusted EBITDA measures reported by other companies.
A reconciliation of combined Drilling Services Segment margin and Production Services Segment margin to net income (loss), as reported, and a reconciliation of Adjusted EBITDA to net income (loss), as reported, are set forth in the following table.
|
| | | | | | | |
| | Year ended December 31, |
| | 2013 | | 2012 |
| | (amounts in thousands) |
| Reconciliation of combined margin and Adjusted EBITDA to net income (loss): | | | |
| Combined margin | $ | 331,748 |
| | $ | 332,822 |
|
| General and administrative | (95,000 | ) | | (85,603 | ) |
| Bad debt (expense) recovery | (767 | ) | | 440 |
|
| Other (expense) income | (1,239 | ) | | 1,624 |
|
| Adjusted EBITDA | 234,742 |
| | 249,283 |
|
| Depreciation and amortization | (187,918 | ) | | (164,717 | ) |
| Impairment charges | (54,292 | ) | | (1,131 | ) |
| Interest expense | (48,310 | ) | | (37,049 | ) |
| Income tax benefit (expense) | 19,846 |
| | (16,354 | ) |
| Net income (loss) | $ | (35,932 | ) | | $ | 30,032 |
|
Our Drilling Services Segment’s revenues increased by $29.5 million, or 6%, during 2013 as compared to 2012, resulting primarily from an increase in revenues per day of 5%, or $1,119 per day, as well as an increase in revenue days of 1%. Our Drilling Services Segment’s operating costs increased by $17.8 million, or 5%, during 2013 as compared to 2012, primarily resulting from higher operating costs per day which increased by 4%, or $657 per day, and partially due to an increase in revenue days.
The increases in our Drilling Services Segment's revenues and operating costs per day were primarily due to increased utilization in Colombia, where our revenues and costs per day are higher than our domestic drilling rigs, as well as the deployment of all our new-build drilling rigs into areas of the U.S. which experience higher revenues and costs per day, due to higher demand. We deployed seven of our new-build drilling rigs during the second half of 2012, with the remaining three in the first quarter of 2013. The overall increases in revenues and operating costs were partially offset by a slight decrease in utilization for our domestic drilling rigs, despite an increase in revenue days attributable to the operations of our new-build drilling rigs during 2013.
Demand for drilling rigs influences the types of drilling contracts we are able to obtain. As demand for drilling rigs decreases, daywork rates move down and we may switch to performing more turnkey drilling contracts to maintain higher utilization rates and to improve our Drilling Services Segment’s margins. Turnkey drilling contracts result in higher average revenues per day and higher average operating costs per day as compared to daywork drilling contracts. During the years ended December 31, 2013 and 2012, we completed 27 and 11 turnkey contracts, respectively, representing 3% and 3% of our total drilling revenues for each year, respectively.
Our Production Services Segment's revenues increased by $11.3 million, or 3%, during 2013, as compared to 2012, while operating costs increased by $24.0 million, or 10%.
The increase in our Production Services Segment's revenues is primarily due to increased rig hours and pricing in our well servicing operations due to higher demand for these services during 2013, as compared to 2012, while the overall increase was partially offset by a decrease in revenues from our coiled tubing operations. The total rig hours of our well servicing fleet increased by 7% for the year ended December 31, 2013, partly due to expansion of
our fleet during 2012 and 2013, while pricing increased by approximately 4%, as compared to 2012. Revenues from our coiled tubing operations decreased as a result of increased competition in the coiled tubing market and our utilization decreased from 59% in 2012 to 47% in 2013.
The increase in our Production Services Segment's operating costs is primarily due to an increase in our operating costs for our wireline operations which incurred higher average costs per job during 2013, as compared to 2012, as well as an increase in costs for our well servicing operations which experienced higher demand during 2013, as compared to 2012. The number of wireline jobs we completed during 2013 was only 1% higher than the number we completed in 2012, while our average cost per job increased by approximately 11%. The increase in our average cost per wireline job during 2013 was primarily due to a greater mix of higher cost jobs performed during the year, as compared to 2012.We also experienced some increase in our operating costs due to modest inflation of labor costs in our Production Services Segment during 2013.
Our general and administrative expense increased by approximately $9.4 million, or 11%during 2013, as compared to 2012, primarily due to the overall expansion of our business in recent years. During 2012, we expanded our well servicing and wireline fleets by approximately 21% and 14%, respectively, and deployed ten new-build drilling rigs during late 2012 and early 2013. The overall expansion of our business increased our general and administrative expense for the year ended December 31, 2013, as compared to 2012, including an increase of $7.0 million in payroll and compensation related expenses primarily resulting from the additional cost of personnel which we have hired over the recent years to support our growth.
Our bad debt recovery for the year ended December 31, 2012 related to the collection of $0.5 million for an account receivable which had been written off prior to 2011.
Our other expense of $1.2 million and other income of $1.6 million for the years ended December 31, 2013 and 2012, respectively, is primarily related to foreign currency exchange gains and losses recognized for our Colombian operations.
Our depreciation and amortization expenses increased by $23.2 millionduring 2013 as compared to 2012, as a result of our expansion in both our drilling and production services segments. The addition of our new-build drilling rigs that went into service in late 2012 and early 2013 resulted in an increase of approximately $12.1 million during the year ended December 31, 2013, as compared to 2012, while the remaining increase is primarily due to the expansion of our well servicing, wireline and coiled tubing fleets in 2012 and 2013.
We recorded impairment charges on our property and equipment of $9.5 million for the year ended December 31, 2013 in association with our decision to place eight of our mechanical drilling rigs and other production services equipment as held for sale. During the year ended December 31, 2012, we recorded impairment charges on our property and equipment of $1.1 million in association with our decision to retire two mechanical drilling rigs, with most of their components to be used as spare parts, as well as two wireline units and other wireline equipment.
During the year ended December 31, 2013, we recorded $44.8 million of impairment charges to reduce the goodwill and intangible asset carrying values of our coiled tubing reporting unit, which were originally recorded in connection with the acquisition of Go-Coil on December 31, 2011. On June 30, 2013, we performed an impairment analysis that led us to conclude that there would be no remaining implied value attributable to our goodwill and accordingly, we recorded a non-cash charge of $41.7 million for the full impairment of our goodwill. In addition, we performed an intangible asset impairment analysis on June 30, 2013, which resulted in a non-cash impairment charge of $3.1 million to reduce our intangible asset carrying value of client relationships. These impairment charges did not have an impact on our liquidity or debt covenants; however, it was a reflection of the increased competition in certain coiled tubing markets where we operate and a decline in our projected cash flows for the coiled tubing reporting unit.
Our interest expense increased by $11.3 million for the year ended December 31, 2013, as compared to the year ended December 31,2012, primarily due to less capitalized interest during the year ended December 31, 2013, as compared to 2012, associated with the capital expenditures for our new-build drilling rigs and for upgrades to our drilling rig fleet.
Our effective income tax rate for the year ended December 31, 2013 was 36%, which is slightly higher than the federal statutory rate in the United States, due to the impact of state income taxes, and partially offset by the effect of foreign translation, the impact of lower effective tax rates in foreign jurisdictions and other permanent differences.
Statements of Operations Analysis—Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011
The following table provides information about our operations for the years ended December 31, 2012 and 2011 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information).
|
| | | | | | | |
| | Year ended December 31, |
| | 2012 | | 2011 |
| Drilling Services Segment: | | | |
| Revenues | $ | 498,867 |
| | $ | 433,902 |
|
| Operating costs | 333,846 |
| | 292,559 |
|
| Drilling Services Segment margin | $ | 165,021 |
| | $ | 141,343 |
|
| | | | |
| Average number of drilling rigs | 65.0 |
| | 69.3 |
|
| Utilization rate | 87 | % | | 73 | % |
| Revenue days | 20,728 |
| | 18,383 |
|
| | | | |
| Average revenues per day | $ | 24,067 |
| | $ | 23,603 |
|
| Average operating costs per day | 16,106 |
| | 15,915 |
|
| Drilling Services Segment margin per day | $ | 7,961 |
| | $ | 7,688 |
|
| | | | |
| Production Services Segment: | | | |
| Revenues | $ | 420,576 |
| | $ | 282,039 |
|
| Operating costs | 252,775 |
| | 164,365 |
|
| Production Services Segment margin | $ | 167,801 |
| | $ | 117,674 |
|
| | | | |
| Combined: | | | |
| Revenues | $ | 919,443 |
| | $ | 715,941 |
|
| Operating costs | 586,621 |
| | 456,924 |
|
| Combined margin | $ | 332,822 |
| | $ | 259,017 |
|
| Adjusted EBITDA | $ | 249,283 |
| | $ | 183,870 |
|
Drilling Services Segment margin represents contract drilling revenues less contract drilling operating costs. Production Services Segment margin represents production services revenue less production services operating costs. We believe that Drilling Services Segment margin and Production Services Segment margin are useful measures for evaluating financial performance, although they are not measures of financial performance under U.S. Generally Accepted Accounting Principles (GAAP). However, Drilling Services Segment margin and Production Services Segment margin are common measures of operating performance used by investors, financial analysts, rating agencies and Pioneer’s management. Drilling Services Segment margin and Production Services Segment margin as presented may not be comparable to other similarly titled measures reported by other companies.
Adjusted EBITDA is a financial measure that is not in accordance with GAAP, and should not be considered (a) in isolation of, or as a substitute for, net income (loss), (b) as an indication of cash flows from operating activities or (c) as a measure of liquidity. In addition, Adjusted EBITDA does not represent funds available for discretionary use. We define Adjusted EBITDA as income (loss) before interest income (expense), taxes, depreciation, amortization
and any impairments. We use this measure, together with our GAAP financial metrics, to assess our financial performance and evaluate our overall progress towards meeting our long-term financial objectives. We believe that this non-GAAP financial measure is useful to investors and analysts in allowing for greater transparency of our operating performance and makes it easier to compare our results with those of other companies within our industry. Adjusted EBITDA, as we calculate it, may not be comparable to Adjusted EBITDA measures reported by other companies.
A reconciliation of combined Drilling Services Segment margin and Production Services Segment margin to net income (loss), as reported, and a reconciliation of Adjusted EBITDA to net income (loss), as reported, are set forth in the following table.
|
| | | | | | | |
| | Year ended December 31, |
| | 2012 | | 2011 |
| | (amounts in thousands) |
| Reconciliation of combined margin and Adjusted EBITDA to net income: | | | |
| Combined margin | $ | 332,822 |
| | $ | 259,017 |
|
| General and administrative | (85,603 | ) | | (67,318 | ) |
| Bad debt recovery (expense) | 440 |
| | (925 | ) |
| Other income (expense) | 1,624 |
| | (6,904 | ) |
| Adjusted EBITDA | 249,283 |
| | 183,870 |
|
| Depreciation and amortization | (164,717 | ) | | (132,832 | ) |
| Impairment of equipment | (1,131 | ) | | (484 | ) |
| Interest expense | (37,049 | ) | | (29,721 | ) |
| Income tax expense | (16,354 | ) | | (9,656 | ) |
| Net income | $ | 30,032 |
| | $ | 11,177 |
|
Our Drilling Services Segment experienced increases in its revenues and operating costs due to higher demand for our domestic drilling services in 2012 as compared to 2011, as our industry continues to recover from the downturn that bottomed in late 2009. Domestic revenues increased as a result of increasing oil prices and rig utilization and improved revenue rates particularly in oil-producing regions and in certain shale regions. Increases in domestic revenues and operating costs were partially offset by decreases in our international revenues and operating costs due to decreased utilization in Colombia.
Our Drilling Services Segment’s revenues increased by $65.0 million, or 15%, during 2012 as compared to 2011, primarily due to an increase in domestic drilling rig utilization and the addition of seven new-build drilling rigs which began operations during 2012. With the increase in demand for our drilling services during 2012, our revenue days increased by 13% during 2012 as compared to 2011, and our revenues per day increased by 2% or $464 per day, despite a decrease in our utilization in Colombia, where we have higher revenues per day. The increase in our domestic drilling rig utilization rate was also impacted by our decision to dispose of seven drilling rigs in September 2011 and another two drilling rigs in March 2012.
Our Drilling Services Segment’s operating costs increased by $41.3 million, or 14%, during 2012 as compared to 2011, primarily due to the increase in domestic utilization and the addition of seven new-build drilling rigs which began operations during 2012. Our operating costs per day increased by 1% or $191 per day, during 2012 as compared to 2011, primarily due to increases in supplies, repair and maintenance costs and increased mobilization costs for drilling rigs that were moved between our domestic drilling divisions during 2012. The increase in our operating costs per day was partially offset by a decrease in our international operating costs due to decreased utilization in Colombia, where we have higher operating costs per day.
Demand for drilling rigs influences the types of drilling contracts we are able to obtain. As demand for drilling rigs decreases, daywork rates move down and we may switch to performing more turnkey drilling contracts to maintain higher utilization rates and to improve our Drilling Services Segment’s margins. Turnkey drilling contracts result in
higher average revenues per day and higher average operating costs per day as compared to daywork drilling contracts. During the years ended December 31, 2012 and 2011, we completed 11 and 17 turnkey contracts, respectively, representing 3% and 4% of our total drilling revenues for each year, respectively.
Our Production Services Segment's revenues increased by $138.5 million, or 49%, during 2012 as compared to 2011, while operating costs increased $88.4 million, or 54%. The acquisition of Go-Coil on December 31, 2011 resulted in an increase in our revenues and operating expenses during 2012 of $58.4 million and $40.9 million, respectively. The remaining increases in revenues and operating costs are primarily due to the expansion of our operations through fleet additions as well as higher demand for our wireline and well servicing offerings, which resulted in higher utilization rates and higher revenue rates charged for these services during the year ended December 31, 2012, as compared to 2011. During 2011 and 2012, we acquired a total of 34 well servicing rigs and 36 wireline units, resulting in an increase in both our revenues and operating costs. Utilization of our well servicing fleet also increased to 91% for the year ended December 31, 2012, as compared to 87% during 2011, while pricing increased by approximately 10%. The number of wireline jobs we completed increased by approximately 7% for the year ended December 31, 2012, as compared to 2011, and our average price per job increased by approximately 14%, which is partially due to a greater mix of higher priced jobs performed as well as increased demand.
Our general and administrative expense increased by approximately $18.3 million, or 27%, during 2012 as compared to 2011, primarily due to the overall expansion of our operations in both our drilling and production services segments. The acquisition of Go-Coil on December 31, 2011 resulted in an increase of $7.3 million in our general and administrative expense for the year ended December 31, 2012, as compared to 2011. Additionally, during 2012, we expanded our well servicing and wireline fleets by approximately 21% and 14%, respectively, and deployed seven new-build drilling rigs. The overall expansion of our business increased our general and administrative expense for the year ended December 31, 2012, as compared to 2011, including an increase of $5.5 million in payroll and compensation related expenses primarily resulting from the hiring of additional personnel to support our growth.
Our bad debt recovery for the year ended December 31, 2012 related to the collection of $0.5 million for an account receivable which had been written off prior to 2011.
Our other income for the year ended December 31, 2012 includes $0.6 million recognized for the redemption of certain Auction Rate Preferred Securities ("ARPSs") on October 1, 2012. Our other expense for the year ended December 31, 2011 primarily related to the $7.3 million net-worth tax expense for our Colombian operations, which was assessed on January 1, 2011, and was partially reduced by $0.5 million of income recognized for our ARPSs Call Option in January 2011.
Our depreciation and amortization expenses increased by $31.9 million during 2012, as compared to 2011, as a result of our expansion in both our drilling and production services segments. The expansion of our well servicing and wireline fleets resulted in an increase of approximately $12.5 million during the year ended December 31, 2012, as compared to 2011, and the acquisition of Go-Coil on December 31, 2011 resulted in an increase of $10.3 million. The remaining increase is primarily due to the expansion of our drilling services fleet through the addition of seven new-build drilling rigs that went into service in 2012 as well as capital expenditures for upgrades to our drilling rig fleet during 2012 and late 2011.
During the year ended December 31, 2012, we recorded impairment charges of $1.1 million in association with our decision to retire two drilling rigs, with most of their components to be used as spare parts, and to retire two wireline units and certain wireline equipment.
Our interest expense increased for the year ended December 31, 2012, as compared to the year ended December 31, 2011, primarily due to the issuance of our Senior Notes in November 2011. The issuance of our Senior Notes in November 2011 increased our overall debt balance in 2012. The overall increase in interest expense was partially offset by $10.2 million of capitalized interest during the year ended December 31, 2012, associated with the capital expenditures for upgrades to our drilling rig fleet and for our new-build drilling rigs.
Our effective income tax rate for the year ended December 31, 2012 was 35%, which is the same as the federal statutory rate in the United States, primarily due to the impact of state income taxes that were offset by lower effective tax rates in foreign jurisdictions, the effect of foreign translation and other permanent differences.
Inflation
Wage rates for our operations personnel are impacted by inflationary pressures when the demand for drilling and production services increases and the availability of personnel is scarce. With the increase in demand from 2010 through 2011, and the resulting tightening of labor markets, we had a wage rate increase of approximately 10% across multiple drilling divisions in January 2012. During 2013, we have experienced modest wage rate increases in our Production Services Segment and we expect similar pressure in 2014.
Costs for rig repairs and maintenance, rig upgrades and new rig construction are also impacted by inflationary pressures when the demand for drilling services increases. We estimate that we experienced an increase in these costs of approximately 5% to 10% during 2012 and 2013, and we estimate that we will experience a more moderate increase in 2014.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Critical Accounting Policies and Estimates
Revenue and cost recognitionCost Recognition—Our Drilling Services DivisionSegment earns revenues by drilling oil and gas wells for our customersclients under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. Drilling contracts for individual wells are usually completed in less than60days. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each contract. Individual contractsAll our revenues are usually completed in less than 60 days. The risks to us under a turnkey contract and, to a lesser extent, under footage contracts, are substantially greater than on a contract drilled on a daywork basis. Under a turnkey contract, we assume mostrecognized net of the risks associated with drilling operations that are generally assumed by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors’ services, supplies, cost escalations and personnel operations.applicable sales taxes. Our management has determined that it is appropriate to use the percentage-of-completion method as defined in the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 605,Revenue Recognition, to recognize revenue on our turnkey and footage contracts. Although our turnkey and footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed-on depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed-on depth in breach of the applicable contract. However, in the event we were unable to drill to the agreed-on depth in breach of the contract, ultimate recovery of that value would be subject to negotiations with the customerclient and the possibility of litigation. If a customerclient defaults on its payment obligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and footage contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed-on depth in breach of the contract, we also would need to rely on equitable remedies outside of the contract available in applicable courts to recover the fair value of our work-in-progress under a turnkey or footage contract. The risks to us under a turnkey contract and, to a lesser extent, under footage contracts, are substantially greater than on a contract drilled on a daywork basis. Under a turnkey contract, we assume most of the risks associated with drilling operations that are generally assumed by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors’ services, supplies, cost escalations and personnel operations.
We accrue estimated contract costs on turnkey and footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance, operating overhead allocations and allocations of depreciation and amortization expense. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and footage contracts could have amaterial adverse effect on our financial position and results of operations. Therefore, our actual results for a contract could differ significantly if our cost estimates for that contract are later revised from our original cost estimates for a contract in progress at the end of a reporting period which was not completed prior to the release of our financial statements.
statements
.
With most drilling contracts, we receive payments contractually designated for the mobilization of rigs and other equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on a straight line basis over the related contract term. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses are recorded as revenue and the out-of-pocket expenses for which they relate are recorded as operating costs.The asset “unbilled receivables” represents revenues we have recognized in excess of amounts billed on drilling contracts and production services completed but not yet invoiced.
The assets “prepaid expenses and other current assets” and “other long-term assets” include the current and long-term portions of deferred mobilization costs for certain drilling contracts. The liabilities “prepaid drilling contracts”“deferred revenues” and “other long-term liabilities” include the current and long-term portions of deferred mobilization revenues for certain drilling contracts and amounts collected on contracts in excess of revenues recognized. As ofDecember 31, 2010 2013we had $6.3$0.7 millionand $0.9 millionof current deferred mobilization revenues and costs, respectively, and $0.4 millionand$0.5 millionof which the current portion was $3.7 million. The relatedlong-term deferred mobilization revenues and costs, were $5.8 million, of which the current portion was $3.3 million.respectively. Our deferred mobilization costs and revenues primarily related to long-term contracts for our Colombian operations,new-build drilling rigs and long-term contracts for drilling rigs which are being amortized through the year ending December 31, 2012.we moved between drilling divisions. Amortization of deferred mobilization revenues was $3.0$5.3 million, $6.3 million and $5.1 million for the year yearsendedDecember 31, 2010.2013
, 2012 and 2011, respectively. Our Production Services DivisionSegment earns revenues for well servicing, wireline services, wirelinecoiled tubing services and fishing and rental services pursuant to master services agreements based on purchase orders, contracts or other persuasive evidence of an arrangementarrangements with the customerclient that include fixed or determinable prices. Production services jobs are generally short-term and are charged at current market rates. Production service revenue is recognized when the service has been rendered and collectability is reasonably assured. The asset “unbilled receivables” represents revenues we have recognized in excess of amounts billed on drilling contracts and production services completed but not yet invoiced. Our unbilled receivables totaled $49.5 million at December 31, 2013, of which $45.4 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at December 31, 2013 and $4.1 million related to unbilled receivables for our Production Services Segment.
Long-lived Assetstangible and Intangible Assets—intangible assets—We evaluate for potential impairment of long-lived assetstangible and intangible assets subject to amortization when indicators of impairment are present, as defined in ASC Topic 360,Property, Plant, and Equipment and ASC Topic 350,Intangibles—Goodwill and Other.present. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts for drilling rigs and well serviceservicing rigs. In performing thean impairment evaluation, we estimate the future undiscounted net cash flows relating tofrom the use and eventual disposition of long-lived assetstangible and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services Division, our long-lived assetsSegment, we perform an impairment evaluation and intangible assets are grouped atestimate future undiscounted cash flows for the individual reporting unit level which is one level below the operating segment level. units (well servicing, wireline, coiled tubing and fishing and rental services).For our Drilling Services Division,Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual drilling rig assets.If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the long-lived assets and intangible assets for these asset grouping levels,group, then we would recognize an impairment charge.determine the fair value of the asset group. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in the impairment evaluation for long-lived assets and intangible assets are inherently uncertain and require management judgment.We
Due to several significant adverse factors affecting our coiled tubing services reporting unit, including increased competition in certain coiled tubing markets, turnover of key personnel and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of ourlong-lived assetstangible and intangible assets at December 31, 2008, due to significant adverse changes in the economic and business climate that resulted in decreases in estimated revenues, margins and cash flows. Essentially all our intangible assets were recorded in connection with the acquisitionsas of the production services businesses from WEDGE, Competition, Pettus and Paltec when revenues, margins and cash flows were at historically high levels in early 2008.June 30, 2013. We determined that the sum of the estimated future undiscounted net cash flows for our coiled tubing services reporting unit was less than the carrying amount at June 30, 2013. We then performed a valuation of the long-lived assets andintangible assets in each reporting unit at December 31, 2008. Our long-lived asset and intangible asset impairment analysis for the reporting units in our Production Services Divisionwhich resulted in no impairment charge to property and equipment and a non-cash impairment charge of $52.8
$3.1 millionto thereduce our intangible asset carrying value of our intangible assets for customers relationships for the year ended December 31, 2008. client relationships.This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the overall downturn increased competition
in our industrycertain coiled tubing markets where we operate and a decline in our projected cash flows. Weflows for the coiled tubing reporting unit.
The most significant inputs used in our impairment analysis include the projected utilization and pricing of our coiled tubing services, which are classified as Level 3 inputs as defined by ASC Topic 820,Fair Value Measurements and Disclosures.An increase of 1% in either the utilization or pricing assumptions would have resulted in a decrease to our impairment charge for our long-lived intangible assets of approximately $1 million. Similarly, a decrease of 1% in either of these assumptions would have led to an approximate $1 million increase to our impairment charge. Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating fair values and performing the impairment test are inherently uncertain and require management judgment.
Our impairment analysis did not recordresult in any impairment charges to our coiled tubing tangible long-lived assets, substantially all of which was related to the 13 coiled tubing units. As discussed further below, we also recorded a non-cash impairment charge to reduce the carrying value of goodwill to zero.
Due to continued increases in competition in certain coiled tubing markets and lower than anticipated operating results, we performed another impairment analysis of our long-lived tangible and intangible assets as of December 31, 2013. We determined that the sum of the estimated future undiscounted net cash flows for our coiled tubing services reporting unit was in excess of the carrying amount and concluded that no impairment existed as of December 31, 2013. The future undiscounted cash flows used in our impairment analysis include projected increases in utilization and pricing from what we have historically experienced. If we fail to meet the projected increases in utilization and pricing for our coiled tubing services, or in the event of significant unfavorable changes in the forecasted cash flows or key assumptions used in our analysis, the most significant of these being the projected utilization and pricing of our coiled tubing services, then we may incur a future impairment.
In September 2013, we evaluated the drilling rigs in our fleet and decided to place eight of our mechanical drilling rigs as held for sale and recognized an impairment charge to reduce the carrying value of these assets to their estimated fair value, which was based on any long-livedtheir sales price. The decision to sell these drilling rigs was primarily due to a decrease in demand for non-top drive mechanical rigs that drill vertical oil and gas wells. Our remaining drilling rig fleet includes mechanical rigs that are currently working, but which may have reduced utilization if demand for vertical drilling continues to soften. We performed an impairment evaluation on the remaining drilling rigs in our fleet which are similar to those that we decided to sell. In order to estimate our future undiscounted cash flows from the use and eventual disposition of these assets, for our Production Services Divisionwe incorporated probabilities of selling these rigs in the near term, versus working them through the end of their remaining useful lives. Our analysis led us to conclude that no impairment presently exists for the years ended December 31, 2010 or 2009. For our Drilling Services Division, we did not recordremaining similar drilling rigs. If the demand for vertical drilling continues to soften and these remaining mechanical rigs become idle for an extended amount of time, then the probability of a near term sale may increase, which would likely result in an impairment charge, based on any long-lived assets for the years ended December 31, 2010, 2009 or 2008.current market value of these drilling rigs. Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions.
Goodwill—Goodwill—Goodwill results from business acquisitions and represents the excess of acquisition costs over the fair value of the net assets acquired. In connection with the acquisition of the production services business from Go-Coil, we recorded $41.7 million of goodwill at December 31, 2011, all of which was allocated to the coiled tubing services reporting unit within our Production Services Segment.
We account forperform a qualitative assessment of goodwill and other intangible assets under the provisions of ASC Topic 350. Goodwill is tested for impairment annually as of December 31 or more frequently if events or changes in circumstances indicate that the asset might be impaired. Circumstances that could indicate a potential impairment include a significant adverse change in the economic or business climate, a significant adverse change in legal factors, an adverse action or assessment by a regulator, unanticipated competition, loss of key personnel and the likelihood that a reporting unit or significant portion of a reporting unit will be sold or otherwise disposed of. TheseIn addition, these circumstances could lead to our net book value exceeding our market capitalization which is another indicator of a potential impairment inof goodwill. ASC Topic 350 requires
If our qualitative assessment of goodwill indicates a possible impairment, we test for goodwill impairment using a two-step process for testing impairment.process. First, the fair value of each reporting unit with goodwill is compared to its carrying value to determine whether an indication of impairment exists. Second, if impairment is indicated, then the fair value of the reporting unit's goodwill is determined by allocating the unit's fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination on the impairment test date. The amount of impairment for goodwill is measured as the excess of the carrying value of the reporting unit over its fair value. Goodwill of $118.6 million was initially recorded in connection with the acquisitions of the production services businesses from WEDGE, Competition, Pettus and Paltec, all of which occurred between March 1, 2008 and October 1, 2008, and was allocated to the three reporting units for our Production Services Division which are well services, wireline services and fishing and rental services. We recorded a full impairment of this goodwill during the year ended December 31, 2008 as further described below. When estimating fair values of a reporting unit for our goodwill impairment test, we use a combination of an income approach and a market approach which incorporates both management’s views and those of the market. The income approach provides an estimated fair value based on eachthe reporting unit’s anticipated cash flows that wereare discounted using a weighted average cost of capital rate. The market approach provides an estimated fair value based on our market capitalization that was computed using the prior 30-day average market price of our common stock and the number of shares outstanding as of the impairment test date. The estimated fair values computed using the income approach and the market approach were then equally weighted and combined into a single fair value. The primary assumptions used in the income approach wereare estimated cash flows and weighted average cost of capital. Estimated cash flows wereare primarily based on projected revenues, operating costs and capital expenditures and are discounted at a rate that is based on comparable industry average rates for weighted average cost of capital. We utilized discount rates based onour weighted average cost of capital ranging from 15.8% to 16.7% when weand estimated fair valuesindustry average rates for cost of our reporting units as of December 31, 2008. The primary assumptions used in the market approach were the allocation of total market capitalization to each reporting unit, which was based on projected EBITDA percentages for each reporting unit, and control premiums, which were based on comparable industry averages. We utilized a 30% control premium when we estimated fair values of our reporting units as of December 31, 2008.capital. To ensure the reasonableness of the estimated fair valuesvalue of our reporting units, we performedconsider current industry market multiples and we perform a reconciliation of our total market capitalization to the total estimated fair value of all our reporting units. The assumptions used
Due to several significant adverse factors affecting our coiled tubing services reporting unit, including increased competition in estimatingcertain coiled tubing markets, turnover of key personnel and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of ourgoodwill as of June 30, 2013. We determined that the fair valuesvalue of our coiled tubing services reporting unitsunit was less than its carrying value, including goodwill, and performingtherefore, we performed the second step of the goodwill impairment test are inherently uncertain and required management judgment.Our common stock price per share declined in market value from $13.30 at September 30, 2008, to $5.57 at December 31, 2008, which resulted in our net book value exceeding our market capitalization during most of that
time period. We concluded that the decline in the market price of our common stock resulted from a significant adverse change in the economic and business climate as financial markets reacted to the credit crisis facing major lending institutions and worsening conditions in the overall economy during the fourth quarter of the year ended December 31, 2008. During the same time, there were significant declines in oil and natural gas prices which led to declines in production service revenues, margins and cash flows. We considered the impact of these significant adverse changes in the economic and business climate as we performed our annual impairment assessment of goodwill as of December 31, 2008. The estimated fair values of our reporting units were negatively impacted by significant reductions in estimated cash flows for the income approach component and a significant reduction in our market capitalization for the market approach component of our fair value estimation process. Our goodwill was initially recorded in connection with the acquisitions of the production services businesses from WEDGE, Competition, Pettus and Paltec, all of which occurred between March 1, 2008 and October 1, 2008, when production service revenues, margins and cash flows and our market capitalization were at historically high levels.
Our goodwill impairment analysis led us to conclude that there would be no remaining implied fair value attributable to our goodwill and, accordingly,goodwill. Accordingly, we recorded a non-cash impairment charge of $118.6
$41.7 millionto our operating results forreduce the year ended December 31, 2008, for the full impairmentcarrying value of our goodwill. Our goodwill impairment analysis would have led to the same full impairment conclusion if we increased or decreased our discount rates or control premiums by 10% when estimating the fair values of our reporting units. zero.This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the overall downturnincreased competition in our industrycertain coiled tubing markets where we operate and a decline in our projected cash flows.flows for the coiled tubing reporting unit.
The most significant inputs used in our impairment analysis include the projected utilization and pricing of our coiled tubing services and the weighted average cost of capital (discount rate) used in order to calculate the discounted cash flows for the reporting unit. These inputs are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures.We had noassumed a 13% discount rate to estimate the fair value of the coiled tubing services reporting unit. A decrease in this assumption of 5% would have resulted in a decrease to our goodwill additions duringimpairment charge of approximately $3.5 million. An increase of 1% in either the years ended December 31, 2010utilization or 2009,pricing assumptions would have resulted in a decrease to our goodwill impairment charge of approximately $2 million or $3 million, respectively. Although we believe the assumptions and consequently, have noestimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating fair values of reporting units and performing the goodwill reflected on our consolidated balance sheets at December 31, 2010impairment test are inherently uncertain and 2009.require management judgment.
Deferred taxes—We provide deferred taxes for the basis differences in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, net operating loss carryforwards, employee benefit and other accrued liabilities which are deducted in different periods for financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs, well serviceservicing rigs, and wireline units and coiled tubing units over 2 to 25 years and refurbishments over 3 to 5 years, while federal income tax rules require that we depreciate drilling rigs, well serviceservicing rigs, and wireline units and coiled tubing units over 5 years. Therefore, in the first 5 years of our ownership of a drilling rig, well serviceservicing rig, wireline unit or wirelinecoiled tubing unit, our tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation difference. After 5 years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse. Accounting estimates—estimates—Material estimates that are particularly susceptible to significant changes in the near term relate to our recognition of revenues and costs for turnkey contracts, our estimate of the allowance for doubtful
accounts, our determination of depreciation and amortization expenses, our estimates of fair value for impairment evaluations, our estimate of deferred taxes, our estimate of the liability relating to the self-insurance portion of our health and workers’ compensation insurance, and our estimate of compensation related accruals.
We consider the recognition of revenues and costs on turnkey and footage contracts to be critical accounting estimates. OnFor these types of contracts, we are required torecognize revenues and accrue estimated costs based on our estimate of the number of days needed for us to complete theeach contract and our estimate of the total costcosts to complete the contract. Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released.
Our initial cost estimates for turnkey and footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we increase our cost estimate to complete the contract. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we accrue the entire amount of the estimated loss, including all costs that are included in our revised estimated cost to complete that contract, in our consolidated statement of operations for that reporting period. However, our actual costs could substantially exceed our estimated costs if we encounter problems such as lost circulation, stuck drill pipe or an underground blowout on contracts still in progress subsequent to the release of the financial statements.
We
receive payment under turnkey and footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a more shallow depth. Since 1995, we have completed all our turnkey or footage contracts. Although our initial cost estimates for turnkey and footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews have previously enabled us to make reasonable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of turnkey and footage contracts takes such risks into consideration.
When we encounter, during the course of our drilling operations,conditions unforeseen in the preparation of our original cost estimate, we increase our cost estimate to complete the contract. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we accrue the entire amount of the estimated loss, including all costs that are included in our revised estimated cost to complete that contract, in our consolidated statement of operations for that reporting period. During the year ended December 31, 2010, we experienced a loss of $0.2 million on one turnkey contract. During the year ended December 31, 2009, we did not experience a loss on any turnkey or footage contracts completed. We are more likely to encounter losses on turnkey and footage contracts in periods in which revenue rates are lower for all types of contracts. DuringHowever, during periods of reduced demand for drilling rigs, our overall profitability on turnkey and footage contracts has historically exceeded our profitability on daywork contracts.
Revenues and costs during
During the year ended December 31, 2013, we experienced a reporting period could be affected for contracts in progress at the endloss of a reporting period which have not been completed before our financial statements for that period are released. We hadapproximately $17,000 on one turnkey and no footagecontract completed. We did not experience a loss on any of the turnkey contracts in progress at completed during 2012. During 2011, we experienced a loss of $1.5 million on two turnkey contracts completed. As of December 31, 2010. The2013, we did not have any turnkey contract was completed prior to the release of the financial statements includedcontracts in this report. Our unbilled receivables totaled $21.4 million at December 31, 2010. Of that amount accrued, turnkey drilling contract revenues were $1.3 million. The remaining balance of unbilled receivables related to $18.7 million of the revenue recognized but not yet billed on daywork drilling contracts in progress at December 31, 2010 and $1.4 million related to unbilled receivables for our Production Services Division.progress.
We estimate an allowance for doubtful accounts based on the creditworthiness of our customersclients as well as general economic conditions. We evaluate the creditworthiness of our customersclients based on commercial credit reports, trade references, bank references, financial information, production information and any past experience we have with the customer.client. Consequently, any change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new customersclients to establish escrow accounts or make prepayments. We typically invoice our customers at 15-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Turnkey and footage contracts are invoiced upon completion of the contract. Our typical contract provides for payment of invoices in 10 to 30 days. We generally do not extend payment terms beyond 30 days and have not extended payment terms beyond 90 days for any of our contracts in the last three fiscal years. We had an allowance for doubtful accounts of $0.7$1.4 million at December 31, 2010 and $0.3 million at December 31, 2009.2013
. Our determination of the useful lives of our depreciable assets, which directly affects our determination of depreciation expense and deferred taxes is also a critical accounting estimate. A decrease in the useful life of our property and equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciation of our drilling, production, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from 2 to 25 years. We record the same depreciation expense whether a drilling rig, well serviceservicing rig, wireline unit or wirelinecoiled tubing unit is idle or working. Our estimates of the useful lives of our drilling, production, transportation and other equipment are based on our more than 3540 years of experience in the oilfield services industry with similar equipment. As of December 31, 2010,2013, we had a $1.2$98.0 million deferred tax asset related to the $3.3 million impairment of our ARPSs which will represent a capital loss for tax treatment purposes. We can recognize a tax benefit associated with this impairment to the extent of capital gains we expect to earn in future periods. We recorded a valuation allowance to fully offset our deferred tax asset relating to this capital loss since we believe capital gains are not likely in future periods.As of December 31, 2010, we had $27.3 million
of deferred tax assets related to foreign and domestic net operating loss and AMT credit carryforwards available to reduce future taxable income. In assessing the realizability of our deferred tax assets, we only recognize a tax benefit to the extent of taxable income that we expect to earn in the jurisdiction in future periods. We estimate that our operations will result in taxable income in excess of our net operating losses and we expect to apply the net operating losses against the current year taxable income and taxable income that we have estimated in future periods.
Our accrued insurance premiums and deductibles as of December 31, 20102013 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately $1.5$3.1 million and our workers’ compensation, general liability and auto liability insurance of approximately $6.6 million. As$7.3 million. We have stop-loss coverage of January 1, 2011, we have a deductible of $150,000$150,000 per covered individual per year under theour health insurance up from $125,000 during 2010. We haveand a deductible of $500,000$500,000 per occurrence under our workers’ compensation insurance. We have deductiblesa deductible of $250,000 and $100,000$250,000 per occurrence under both our general liability insurance and auto liability insurance, respectively.insurance. We accrue for these costs as claims are incurred using an actuarial calculation that is based on industry and our company's historical claim development data, and we accrue the costs of administrative services associated with claims processing. We also evaluate our workers’ compensation claim cost estimates based on estimates provided by a professional actuary. Our stock-based compensation expense includes estimates for certain of our long-term incentive compensation plans which have performance-based award components dependent upon our performance over a set performance period, as compared to the performance of a pre-defined peer group. The accruals for these awards include estimates which affect our stock-based compensation expense, employee related accruals and equity.
As of December 31, 2010, we estimated that ourThe accruals are adjusted based on actual achievement
level will be 80%levels at the end of the
predeterminedpre-determined performance
conditions. The final amount will be determinable in the first quarter of 2011.Results of Operations
Effective March 1, 2008, we acquired the production services businesses of WEDGE and Competition which provide well services, wireline services and fishing and rental services. These acquisitions resulted in the formation of our new operating segment, the Production Services Division. We consolidated the results of these acquisitions from the day they were acquired. These acquisitions affect the comparability from period to period of our historical results, and our historical results may not be indicative of our future results.
Statements of Operations Analysis—Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009
The following table provides information about our operations for the years ended December 31, 2010 and December 31, 2009 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information).
| | | | | | | | |
| | | Years ended
December 31, | |
| | | 2010 | | | 2009 | |
Drilling Services Division: | | | | | | | | |
Revenues | | $ | 312,196 | | | $ | 219,751 | |
Operating costs | | | 227,136 | | | | 147,343 | |
| | | | | | | | |
Drilling Services Division margin | | $ | 85,060 | | | $ | 72,408 | |
| | | | | | | | |
Average number of drilling rigs | | | 71.0 | | | | 70.7 | |
Utilization rate | | | 59 | % | | | 41 | % |
Revenue days | | | 15,182 | | | | 10,491 | |
| | |
Average revenues per day | | $ | 20,564 | | | $ | 20,947 | |
Average operating costs per day | | | 14,961 | | | | 14,045 | |
| | | | | | | | |
Drilling Services Division margin per day | | $ | 5,603 | | | $ | 6,902 | |
| | | | | | | | |
Production Services Division: | | | | | | | | |
Revenues | | $ | 175,014 | | | $ | 105,786 | |
Operating costs | | | 105,295 | | | | 68,012 | |
| | | | | | | | |
Production Services Division margin | | $ | 69,719 | | | $ | 37,774 | |
| | | | | | | | |
Combined: | | | | | | | | |
Revenues | | $ | 487,210 | | | $ | 325,537 | |
Operating costs | | | 332,431 | | | | 215,355 | |
| | | | | | | | |
Combined margin | | $ | 154,779 | | | $ | 110,182 | |
| | | | | | | | |
Adjusted EBITDA | | $ | 103,151 | | | $ | 74,942 | |
| | | | | | | | |
We present Drilling Services Division margin, Production Services Division margin, combined margin and earnings before interest, taxes, depreciation, amortization and impairments (Adjusted EBITDA) information because we believe it provides investors and our management additional information to assist them in assessing our business and performance in comparison to other companies in our industry. Since Drilling Services Division margin, Production Services Division margin, combined margin and Adjusted EBITDA are “non-GAAP” financial measures under the rules and regulations of the SEC, we are providing the following reconciliation of combined margin and Adjusted EBITDA to net loss, which is the nearest comparable GAAP financial measure.
| | | | | | | | |
| | | Year ended
December 31, | |
| | | 2010 | | | 2009 | |
| | | (amounts in thousands) | |
Reconciliation of combined margin and | | | | | | | | |
Adjusted EBITDA to net loss: | | | | | | | | |
Combined margin | | $ | 154,779 | | | $ | 110,182 | |
General and administrative | | | (52,047 | ) | | | (37,478 | ) |
Bad debt recovery (expense) | | | (493 | ) | | | 1,642 | |
Other income | | | 912 | | | | 596 | |
| | | | | | | | |
Adjusted EBITDA | | | 103,151 | | | | 74,942 | |
Depreciation and amortization | | | (120,811 | ) | | | (106,186 | ) |
Interest income (expense), net | | | (26,567 | ) | | | (8,928 | ) |
Impairment of investments | | | (3,331 | ) | | | — | |
Income tax benefit | | | 14,297 | | | | 16,957 | |
| | | | | | | | |
Net loss | | $ | (33,261 | ) | | $ | (23,215 | ) |
| | | | | | | | |
Our Drilling Services Division’s revenues increased by $92.4 million, or 42%, for the year ended December 31, 2010, as compared to the year ended December 31, 2009, due to a 45% increase in revenue days that resulted from an increase in our rig utilization rate to 59% from 41%. We have experienced an increase in the demand for drilling services in 2010 as our industry begins to recover from the downturn that bottomed in late 2009. Consequently, utilization rates and drilling revenue rates have improved in 2010 as compared to 2009. However, when compared to 2009, our Drilling Services Division’s average revenues decreased by $383 per day, or 2%. During 2009, a significant portion of our drilling rigs were still operating or were on standby under long-term drilling contracts that were entered into when drilling rig demand was high and drilling revenues per day were at historically high levels. The positive impact of the higher revenue rates for these long-term contracts had a diminishing affect on our average revenues per day as the contracts expired ratably during 2009. In addition, a larger percentage of our Drilling Services Division’s revenues were attributed to turnkey drilling contracts in 2009 when compared to 2010, and turnkey drilling contracts result in higher average revenues per day than daywork drilling contracts. The overall decreases in our average drilling revenues per day during 2010 as compared to 2009 was partially offset by an increase in our Colombian operations during 2010, as drilling contracts in Colombia have higher revenue rates per day when compared to domestic drilling contracts.
Demand for drilling rigs influences the types of drilling contracts we are able to obtain. As demand for drilling rigs decreases, daywork rates move down and we may switch to performing more turnkey drilling contracts to maintain higher utilization rates and improve our Drilling Services Division’s margins. Turnkey drilling contracts also result in higher average revenues per day and higher average operating costs per day when compared to daywork drilling contracts. We completed 11 turnkey drilling contracts during 2010, as compared to 14 turnkey drilling contracts completed during 2009. The shift to fewer turnkey drilling contracts is due to the increase in the demand for drilling services in 2010. The following table provides percentages of our drilling revenues by drilling contract type for the years ended December 31, 2010 and 2009:
| | | | | | | | |
| | | Years ended
December 31, | |
| | | 2010 | | | 2009 | |
Daywork Contracts | | | 95 | % | | | 90 | % |
Turnkey Contracts | | | 5 | % | | | 10 | % |
Footage Contracts | | | — | | | | — | |
Our Drilling Services Division’s operating costs increased $79.8 million, or 54%, for the year ended December 31, 2010, as compared to the corresponding period in 2009, primarily due to the increase in utilization and the increase in our operating costs of $916 per day, or 7%. The increase in operating costs per day is due to higher average drilling costs per day for our domestic operations, as well as the increase in our Colombian operations during 2010 as compared to the corresponding period in 2009, where we have a higher operating cost per day as compared to our domestic operations. We have seen an increase in the demand for our services during 2010 as our industry begins to recover from the downturn that bottomed in late 2009. As utilization rates began to increase in 2010, average operating costs per day increased due to higher wage rates and repair and maintenance expenses as drilling rigs come out of storage and begin operations. In addition, average operating costs per day in 2009 were lower due to a significant portion of our drilling rigs earning standby revenue rates under longer-term drilling contracts and incurring reduced operating costs. The overall increase in operating costs per day in 2010 was partially offset by a decrease in operating costs per day due to a smaller proportion of our drilling services attributable to turnkey contracts during the year ended December 31, 2010 as compared to the corresponding period in 2009.
Our Production Services Division’s revenues increased by $69.2 million, or 65%, while operating costs increased by $37.3 million, or 55%, for the year ended December 31, 2010, as compared to the corresponding period in 2009. Our Production Services Division experienced increases in its revenue and operating cost due to higher demand for our wireline services, well services and fishing and rental services during 2010 as compared to 2009. The increase in our Production Services Division’s revenues is due primarily to higher utilization rates, especially in the wireline and well services operations, and to a lesser extent, higher revenue rates charged for these services during 2010, as compared to the corresponding period in 2009. We have also expanded our operations in 2010 by adding 21 wireline units resulting in an increase in both revenues and operating costs.
Our general and administrative expense increased by approximately $14.6 million, or 39%, for the year ended December 31, 2010 as compared to the corresponding period in 2009. The increase is primarily due to increases in compensation related expenses. With the industry downturn during 2009, we experienced a decrease in the demand for our services and we responded with workforce reductions, elimination of wage rate increases and reduced bonus compensation. During 2010, we have seen an increase in the demand for our services as our industry begins to recover from the industry downturn in 2009. Compensation related expenses increased during 2010 as we have added employees in our corporate office and have accrued for higher bonuses for 2010.
Bad debt recovery decreased for the year ended December 31, 2010 as compared to the corresponding period in 2009, primarily due to the collection of a customer’s past due account receivable balance in 2009 for which we had previously established a $1.3 million allowance for doubtful accounts in December 2008.
Our other income increased by $0.3 million for the year ended December 31, 2010 as compared to the corresponding period in 2009, primarily due to the increase in foreign currency translation gains in excess of losses recognized in relation to our operations in Colombia.
Our depreciation and amortization expenses increased by $14.6 million for the year ended December 31, 2010, as compared to the corresponding period in 2009. This increase resulted primarily from capital expenditures made to upgrade certain drilling rigs to meet the needs of our customers and obtain new contracts as well as capital expenditures for the acquisition of new wireline units.
Interest expense for the year ended December 31, 2010 primarily related to the outstanding debt balance for our Senior Notes, while interest expense for the year ended December 31, 2009 primarily related to the outstanding debt balance under our Revolving Credit Facility. On March 11, 2010, we issued $250 million of Senior Notes with a coupon interest rate of 9.875%. The Senior Notes were sold with an original issue discount that will result in an effective yield to maturity of approximately 10.677%. The proceeds from the issuance of the Senior Notes were immediately used to make a payment of $234.8 million to reduce the outstanding debt balance under the Revolving Credit Facility. The Revolving Credit Facility had a relatively low interest rate of 3.74% as of December 31, 2009, which was based on the LIBOR rate plus a per annum margin. The Senior Notes have a higher interest rate when compared to the Revolving Credit Facility, which resulted in the increase in interest expense during 2010. In addition, interest expense increased in 2010 as compared to 2009 due to an increase in total outstanding debt which was $280.9 million as of December 31, 2010 as compared to $262.1 million as of December 31, 2009.
Our effective income tax rate for the year ended December 31, 2010 differs from the federal statutory rate in the United States of 35% primarily due to a lower effective tax rate in foreign jurisdictions, state income taxes, valuation allowances and other permanent differences.
Statements of Operations Analysis—Year Ended December 31, 2009 Compared with the Year Ended December 31, 2008
The following table provides information about our operations for the years ended December 31, 2009 and 2008 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information). Our Production Services Division was created on March 1, 2008, when we acquired the production services businesses from WEDGE and Competition.
| | | | | | | | |
| | | Years ended
December 31, | |
| | | 2009 | | | 2008 | |
Drilling Services Division: | | | | | | | | |
Revenues | | $ | 219,751 | | | $ | 456,890 | |
Operating costs | | | 147,343 | | | | 269,846 | |
| | | | | | | | |
Drilling Services Division margin | | $ | 72,408 | | | $ | 187,044 | |
| | | | | | | | |
Average number of drilling rigs | | | 70.7 | | | | 67.4 | |
Utilization rate | | | 41 | % | | | 89 | % |
Revenue days | | | 10,491 | | | | 22,057 | |
Average revenues per day | | $ | 20,947 | | | $ | 20,714 | |
Average operating costs per day | | | 14,045 | | | | 12,234 | |
| | | | | | | | |
Drilling Services Division margin per day | | $ | 6,902 | | | $ | 8,480 | |
| | | | | | | | |
Production Services Division: | | | | | | | | |
Revenues | | $ | 105,786 | | | $ | 153,994 | |
Operating costs | | | 68,012 | | | | 80,097 | |
| | | | | | | | |
Production Services Division margin | | $ | 37,774 | | | $ | 73,897 | |
| | | | | | | | |
Combined: | | | | | | | | |
Revenues | | $ | 325,537 | | | $ | 610,884 | |
Operating costs | | | 215,355 | | | | 349,943 | |
| | | | | | | | |
Combined margin | | $ | 110,182 | | | $ | 260,941 | |
| | | | | | | | |
Adjusted EBITDA | | $ | 74,942 | | | $ | 214,766 | |
| | | | | | | | |
We present drilling margin and earnings before interest, taxes, depreciation and amortization (Adjusted EBITDA) information because we believe it provides investors and our management additional information to assist them in assessing our business and performance in comparison to other companies in our industry. Since drilling margin and Adjusted EBITDA are “non-GAAP” financial measures under the rules and regulations of the SEC, we are providing the following reconciliation of drilling margin and Adjusted EBITDA to net earnings, which is the nearest comparable GAAP financial measure.
| | | | | | | | |
| | | Years ended
December 31, | |
| | | 2009 | | | 2008 | |
| | | (amounts in thousands) | |
Reconciliation of combined margin and | | | | | | | | |
Adjusted EBITDA to net loss: | | | | | | | | |
Combined margin | | $ | 110,182 | | | $ | 260,941 | |
General and administrative | | | (37,478 | ) | | | (44,834 | ) |
Bad debt recovery (expense) | | | 1,642 | | | | (423 | ) |
Other income (expense) | | | 596 | | | | (918 | ) |
| | | | | | | | |
Adjusted EBITDA | | | 74,942 | | | | 214,766 | |
Depreciation and amortization | | | (106,186 | ) | | | (88,145 | ) |
Impairment of goodwill | | | — | | | | (118,646 | ) |
Impairment of intangible assets | | | — | | | | (52,847 | ) |
Interest expense, net | | | (8,928 | ) | | | (11,816 | ) |
Income tax expense | | | 16,957 | | | | (6,057 | ) |
| | | | | | | | |
Net loss | | $ | (23,215 | ) | | $ | (62,745 | ) |
| | | | | | | | |
Our Drilling Services Division’s revenues decreased by $237.1 million, or 52%, for the year ended December 31, 2009 as compared to the corresponding period in 2008, due to a 52% decrease in revenue days that resulted from a decline in our rig utilization rate from 89% to 41%. In contrast to the decrease in our Drilling Services Division’s revenues, our average contract drilling revenues per day increased by $233, or 1%. This increase in average drilling revenues per day is attributable to higher average drilling revenues per day for our Colombian operations which represented a larger portion of our drilling revenues for 2009 as compared to 2008. Our average drilling revenues per day for our domestic operations decreased by 8% for the year ended December 31, 2009, since the demand for drilling rigs decreased during 2009 as compared to 2008. The decrease in our average drilling revenues per day for our domestic operations is less than expected because a significant portion of our domestic drilling rigs were operating or were on standby under longer-term drilling contracts that were entered into when drilling rig demand was high and revenues per day were at historically high levels.
Demand for drilling rigs influences the types of drilling contracts we are able to obtain. As demand for drilling rigs decreases, daywork rates move down and we may switch to performing more turnkey drilling contracts to maintain higher utilization rates and improve our Drilling Services Division’s margins. We completed 14 turnkey drilling contracts during the year ended December 31, 2009 as compared to ten turnkey drilling contracts completed during the year ended December 31, 2008. The following table provides percentages of our drilling revenues by drilling contract type for the years ended December 31, 2009 and 2008:
| | | | | | | | |
| | | Years ended
December 31, | |
| | | 2009 | | | 2008 | |
Daywork Contracts | | | 90 | % | | | 93 | % |
Turnkey Contracts | | | 10 | % | | | 2 | % |
Footage Contracts | | | — | | | | 5 | % |
Our Drilling Services Division’s operating costs declined by $122.5 million, or 45%, for the year ended December 31, 2009 as compared to the corresponding period in 2008, primarily due to a 52% decrease in revenue days that resulted from a decline in our rig utilization rate from 89% to 41%. In contrast to the decrease in our Drilling Services Division’s operating costs, our average operating costs per day increased by $1,811, or 15%, primarily due to higher average drilling costs per day for our Colombian operations which represented a larger portion of our drilling costs for 2009 as compared to 2008. In addition, average operating costs per day increased due to a shift to more turnkey contracts and fixed overhead costs associated with division offices, supervisory level employees, insurance and property taxes. Since we had a significant decrease in revenue days, these fixed overhead costs result in an increase in average operating costs per revenue day.
For the year ended December 31, 2009, our Production Services Division’s revenue decreased by $48.2 million, or 31%, while operating costs decreased by $12.1 million, or 15%, as compared to the corresponding period in 2008. Our Production Services Division experienced decreases in its revenue and operating cost due to lower demand for well services, wireline services and fishing and rental services during the year ended December 31, 2009, as compared to the corresponding period in 2008. This decrease in revenues and operating costs that was due to lower demand was partially offset by the timing impact of the WEDGE and Competition acquisitions on March 1, 2008 which created our Production Services Division. A full year of Production Services Division operations are reflected in the operating results for the year ended December 31, 2009, as compared to ten months of operating results for the corresponding period in 2008.
Our general and administrative expense for the year ended December 31, 2009 decreased by approximately $7.4 million, or 16%, as compared to the corresponding period in 2008. Professional and consulting expenses decreased by $5.2 million and compensation related expenses decreased by $2.8 million for the year ended December 31, 2009, as compared to the corresponding period in 2008. We incurred professional and consulting expenses in 2008 related to an investigation conducted by the special committee of our Board of Directors and for the acquisitions of the production services businesses from WEDGE and Competition. The decrease in compensation related expenses is primarily due to decreases in bonus compensation and salary compensation related to workforce reductions in 2009 as compared to 2008. The overall decrease in general and administrative expense was partially offset by increases in insurance expenses and general and administrative expenses relating to our Production Services Division. As noted above, a full year of Production Services Division operations are reflected in the results of operations for the year ended December 31, 2009, as compared to ten months of operating results for the year ended December 31, 2008.
The bad debt recovery during the year ended December 31, 2009 was primarily due to the collection of a customer’s past due account receivable balance for which we had previously established a $1.3 million allowance for doubtful accounts in December 2008.
Our other income for the year ended December 31, 2009 increased by $1.5 million as compared to the corresponding period in 2008, primarily due to foreign currency translation gains and losses relating to our operations in Colombia. We recorded foreign currency translation losses of $0.1 million for the year ended December 31, 2009, and foreign currency translation losses of $1.4 million for the year ended December 31, 2008.
Our depreciation and amortization expenses for the year ended December 31, 2009 increased by $18.0 million, or 20%, as compared to the corresponding period in 2008. This increase resulted primarily from the increase in the fleet size of our drilling rigs, well service rigs and wireline units. The 2009 additions to each fleet consisted primarily of newly constructed equipment. The increase also related to additional depreciation and amortization expense for our new Production Services Division. As noted above, a full year of Production Services Division operations are reflected in the results of operations for the year ended December 31, 2009, as compared to ten months of operating results for the year ended December 31, 2008.
Our interest expense is primarily related to interest due on the amounts outstanding under our senior secured revolving credit facility. Our interest expense decreased $3.9 million for the year ended December 31, 2009, as compared to the corresponding period in 2008. This decrease is due to reductions in the amounts outstanding under our senior secured revolving credit facility and due to decreases in the LIBOR and bank prime base rates used to determine our effective borrowing rate per our senior secured revolving credit facility. Borrowings under the senior secured revolving credit facility were first used to fund the acquisitions of the production services businesses of WEDGE and Competition on March 1, 2008. Operating results for the year ended December 31, 2009 reflect a full year of interest expense as compared to ten months of interest expense for the year ended December 31, 2008.
Our effective income tax rate for the year ended December 31, 2009 differs from the federal statutory rate in the United States of 35% primarily due to pretax income recognized in foreign jurisdictions with a lower effective tax rate, the release of valuation allowance relating to foreign net operating loss carryforwards, state income taxes and other permanent differences.
Inflation
Wage rates for our operations personnel are impacted by inflationary pressures when the demand for drilling and production services increases and the availability of personnel is scarce. From early 2005 to late 2008, the increased rig count in each of our market areas resulted in increased wage rates for our drilling rig personnel. We were able to pass these wage rate increases on to our customers based on contract terms. Beginning in late 2008 and through late 2009, as the rig count in our market areas decreased, we reduced wage rates for drilling rig personnel. With the recent increase in rig counts, beginning in late 2009, we again saw a decreased availability of personnel to operate our rigs and therefore we had additional wage rate increases for drilling rig personnel of approximately 18% and 16% in February and July 2010, respectively.
During the fiscal years ended December 31, 2007 and 2008, we experienced increases in costs for rig repairs and maintenance and costs of rig upgrades and new rig construction, due to the increased industry-wide demand for equipment, supplies and service. We estimate these costs increased by 10% to 15% during the fiscal years ended December 31, 2007 and 2008. We did not experience similar cost increases during 2009; however, we have experienced an increase of approximately 5% during 2010.
Off-Balance Sheet Arrangements
We do not currently have any off-balance sheet arrangements.
Recently Issued Accounting Standards
Multiple Deliverable Revenue Arrangements.In October 2009, the FASB issued Accounting Standards Update (ASU) No. 2009-13, Revenue Recognition (Topic 605):Multiple Deliverable Revenue Arrangements – AConsensus of the FASB Emerging Issues Task Force.This update provides application guidance on whether multiple deliverables exist, how the deliverables should be separated and how the consideration should be allocated to one or more units of accounting. This update establishes a selling price hierarchy for determining the selling price of a deliverable. The selling price used for each deliverable will be based on vendor-specific objective evidence, if available, third-party evidence if vendor-specific objective evidence is not available, or estimated selling price if neither vendor-specific or third-party evidence is available. We will be required to apply this guidance prospectively for revenue arrangements entered into or materially modified after January 1, 2011; however, earlier application is permitted. We do not expect the adoption of this new guidance to have a material impact on our financial position or results of operations.
Business Combinations. In December 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-29, Business Combinations (Topic 805):Disclosure of Supplementary Pro Forma Information for
Business Combinations—A consensus of the FASB Emerging Issues Task Force. This update provides clarification requiring public companies that have completed material acquisitions to disclose the revenue and earnings of the combined business as if the acquisition took place at the beginning of the comparable prior annual reporting period, and also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. We will be required to apply this guidance prospectively for business combinations for which the acquisition date is on or after January 1, 2011. We do not expect the adoption of this new guidance to have a material impact on our financial position or results of operations.
Recently Enacted Regulation
The Colombian government enacted a tax reform act which, among other things, adopted a one-time, net-worth tax for all Colombian entities. The tax is assessed on an entity’s net equity, measured on a Colombian tax basis as of January 1, 2011, and is payable in eight semi-annual installments from 2011 through 2014. Based on our Colombian operations’ net equity, as defined, we estimate that our total net-worth tax obligation is approximately $7.3 million, which is not deductible for tax purposes. In January 2011, the actual net-worth tax obligation will be recognized in full in other expense in our consolidated statement of operations and in other accrued expenses and other long-term liabilities on our consolidated balance sheet.
periods.Item 7A.Quantitative and Qualitative Disclosures About Market Risk
| |
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
We are subject to interest rate market risk on our variable rate debt. As of December 31, 2010,2013, we had $37.8$80.0 million outstanding under our Revolving Credit Facility, subject towhich is our only variable interest rate risk.debt. The impact of a hypothetical 1% increase or decrease in interest rates on this amount of debt would have resulted in increaseda corresponding increase or decrease, respectively, in interest expense of approximately $0.4$0.8 million, and a corresponding increase or decrease, respectively, in net income of approximately $0.2$0.5 million during 2010.At the
year ended December 31, 2010, we held $15.9 million (par value)2013. This potential increase or decrease is based on the simplified assumption that the level of investments comprised of tax exempt, auctionvariable rate preferred securities (ARPS), which were variable-rate preferred securities and had a long-term maturitydebt remains constant with thean immediate across-the-board interest rate being reset through “Dutch auctions” that were held every seven days. The ARPSs had historically traded at par becauseincrease or decrease as of the frequent interest rate resets and because they were callable at par at the option of the issuer. Interest was paid at the end of each auction period. Our ARPSs were AAA/Aaa rated securities, collateralized by municipal bonds and backed by assets that were equal to or greater than 200% of the liquidation preference. Until February 2008, the auction rate securities market was highly liquid. Beginning mid-February 2008, we experienced several “failed” auctions, meaning that there was not enough demand to sell all of the securities that holders desired to sell at auction. The immediate effect of a failed auction is that such holders could not sell the securities at auction and the interest rate on the security reset to a maximum auction rate. We continued to receive interest payments on our ARPSs in accordance with their terms.On January 19, 2011, we entered into an agreement with a financial institution to sell the ARPSs for $12.6 million, which represents 79% of the par value, plus accrued interest. Under the agreement, we retained the unilateral right for a period ending January 7, 1,
2013 to: (a) repurchase all the ARPSs that were sold at the $12.6 million price at which they were initially sold to the financial institution; and (b) if not repurchased, receive additional proceeds from the financial institution upon redemption of the ARPSs by the original issuer of these securities.. While the U.S. dollar is the functional currency for reporting purposes for our Colombian operations, we enter into transactions denominated in Colombian pesos. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the period. As a result, Colombian Peso denominated transactions are affected by changes in exchange rates. We generally accept the exposure to exchange rate movements without using derivative financial instruments to manage this risk. Therefore, both positive and negative movements in the Colombian Peso currency exchange rate against the U.S. dollar has and will continue to affect the reported amount of revenues, expenses, profit, and assets and liabilities in
the Company’sour consolidated financial statements.
The impact of currency rate changes on our Colombian Peso denominated transactions and balances resulted in foreign currency gainslosses of $0.4$2.7 million for the year ended December 31, 2010.2013
.
| |
Item 8.8. | Financial Statements and Supplementary Data |
PIONEER
DRILLING COMPANYENERGY SERVICES CORP.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Pioneer
Drilling Company:Energy Services Corp.:
We have audited the accompanying consolidated balance sheets of Pioneer Drilling CompanyEnergy Services Corp. and subsidiaries as of December 31, 20102013 and 2009,2012, and the related consolidated statements of operations, shareholders’ equity, and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2010.2013. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Pioneer Drilling CompanyEnergy Services Corp. and subsidiaries as of December 31, 20102013 and 2009,2012, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010,2013, in conformity with U.S. generally accepted accounting principles. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Pioneer Drilling Company’sEnergy Services Corp.’s internal control over financial reporting as of December 31, 2010,2013, based on criteria established inInternal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 17, 201113, 2014 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. February 17, 201113, 2014
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Pioneer
Drilling Company:Energy Services Corp.:
We have audited Pioneer Drilling Company’sEnergy Services Corp.'s internal control over financial reporting as of December 31, 2010,2013, based on criteria established inInternal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Pioneer Drilling Company’sEnergy Services Corp.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Pioneer Drilling CompanyEnergy Services Corp. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010,2013, based on criteria established inInternal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Pioneer Drilling CompanyEnergy Services Corp. and subsidiaries as of December 31, 20102013 and 2009,2011, and the related consolidated statements of operations, shareholders’ equity, and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2010,2013, and our report dated February 17, 201113, 2014 expressed an unqualified opinion on those consolidated financial statements. February 17, 201113, 2014
PIONEER DRILLING COMPANYENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
|
| | | | | | | |
| | December 31,
2013 | | December 31,
2012 |
| | (In thousands, except share data) |
| ASSETS | |
| Current assets: | | | |
| Cash and cash equivalents | $ | 27,385 |
| | $ | 23,733 |
|
| Receivables: | | | |
| Trade, net of allowance for doubtful accounts | 115,908 |
| | 115,070 |
|
| Unbilled receivables | 49,535 |
| | 35,140 |
|
| Insurance recoveries | 8,607 |
| | 6,518 |
|
| Income taxes and other | 2,310 |
| | 2,116 |
|
| Deferred income taxes | 13,092 |
| | 11,058 |
|
| Inventory | 13,232 |
| | 12,111 |
|
| Prepaid expenses and other current assets | 9,311 |
| | 13,040 |
|
| Total current assets | 239,380 |
| | 218,786 |
|
| Property and equipment, at cost | 1,724,124 |
| | 1,698,517 |
|
| Less accumulated depreciation | 786,467 |
| | 684,177 |
|
| Net property and equipment | 937,657 |
| | 1,014,340 |
|
| Intangible assets | 32,269 |
| | 43,843 |
|
| Goodwill | — |
| | 41,683 |
|
| Noncurrent deferred income taxes | 1,156 |
| | 5,519 |
|
| Other long-term assets | 19,161 |
| | 15,605 |
|
| Total assets | $ | 1,229,623 |
| | $ | 1,339,776 |
|
| | | | |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current liabilities: | | | |
| Accounts payable | $ | 43,718 |
| | $ | 83,823 |
|
| Current portion of long-term debt | 2,847 |
| | 872 |
|
| Deferred revenues | 699 |
| | 3,880 |
|
| Accrued expenses: | | | |
| Payroll and related employee costs | 30,020 |
| | 27,991 |
|
| Insurance premiums and deductibles | 10,940 |
| | 9,708 |
|
| Insurance claims and settlements | 8,607 |
| | 6,348 |
|
| Interest | 12,275 |
| | 12,343 |
|
| Other | 11,727 |
| | 11,585 |
|
| Total current liabilities | 120,833 |
| | 156,550 |
|
| Long-term debt, less current portion | 499,666 |
| | 518,725 |
|
| Noncurrent deferred income taxes | 84,636 |
| | 108,838 |
|
| Other long-term liabilities | 6,055 |
| | 7,983 |
|
| Total liabilities | 711,190 |
| | 792,096 |
|
| Commitments and contingencies (Note 12) |
| |
|
| Shareholders’ equity: | | | |
| Preferred stock, 10,000,000 shares authorized; none issued and outstanding | — |
| | — |
|
| Common stock $.10 par value; 100,000,000 shares authorized; 62,534,636 and 62,032,517 shares outstanding at December 31, 2013 and 2012, respectively | 6,275 |
| | 6,217 |
|
| Additional paid-in capital | 456,812 |
| | 449,554 |
|
| Treasury stock, at cost; 219,304 and 134,612 shares at December 31, 2013 and 2012, respectively | (1,895 | ) | | (1,264 | ) |
| Accumulated earnings | 57,241 |
| | 93,173 |
|
| Total shareholders’ equity | 518,433 |
| | 547,680 |
|
| Total liabilities and shareholders’ equity | $ | 1,229,623 |
| | $ | 1,339,776 |
|
See accompanying notes to consolidated financial statements.
PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
|
| | | | | | | | | | | |
| | Year ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (In thousands, except per share data) |
| Revenues: | | | | | |
| Drilling services | $ | 528,327 |
| | $ | 498,867 |
| | $ | 433,902 |
|
| Production services | 431,859 |
| | 420,576 |
| | 282,039 |
|
| Total revenues | 960,186 |
| | 919,443 |
| | 715,941 |
|
| Costs and expenses: | | | | |
|
| Drilling services | 351,630 |
| | 333,846 |
| | 292,559 |
|
| Production services | 276,808 |
| | 252,775 |
| | 164,365 |
|
| Depreciation and amortization | 187,918 |
| | 164,717 |
| | 132,832 |
|
| General and administrative | 95,000 |
| | 85,603 |
| | 67,318 |
|
| Bad debt expense (recovery) | 767 |
| | (440 | ) | | 925 |
|
| Impairment charges | 54,292 |
| | 1,131 |
| | 484 |
|
| Total costs and expenses | 966,415 |
| | 837,632 |
| | 658,483 |
|
| Income (loss) from operations | (6,229 | ) | | 81,811 |
| | 57,458 |
|
| Other (expense) income: | | | | |
|
| Interest expense | (48,310 | ) | | (37,049 | ) | | (29,721 | ) |
| Other | (1,239 | ) | | 1,624 |
| | (6,904 | ) |
| Total other expense | (49,549 | ) | | (35,425 | ) | | (36,625 | ) |
| Income (loss) before income taxes | (55,778 | ) | | 46,386 |
| | 20,833 |
|
| Income tax benefit (expense) | 19,846 |
| | (16,354 | ) | | (9,656 | ) |
| Net income (loss) | $ | (35,932 | ) | | $ | 30,032 |
| | $ | 11,177 |
|
| | | | | | |
| Income (loss) per common share—Basic | $ | (0.58 | ) | | $ | 0.49 |
| | $ | 0.19 |
|
| | | | | | |
| Income (loss) per common share—Diluted | $ | (0.58 | ) | | $ | 0.48 |
| | $ | 0.19 |
|
| | | | | | |
| Weighted average number of shares outstanding—Basic | 62,213 |
| | 61,780 |
| | 57,390 |
|
| | | | | | |
| Weighted average number of shares outstanding—Diluted | 62,213 |
| | 62,762 |
| | 58,779 |
|
See accompanying notes to consolidated financial statements.
PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEET | | | | | | | | |
| | | December 31,
2010 | | | December 31,
2009 | |
| | | |
| | | (In thousands, except share data) | |
ASSETS | | | | |
Current assets: | | | | | | | | |
Cash and cash equivalents | | $ | 22,011 | | | $ | 40,379 | |
Short-term investments | | | 12,569 | | | | — | |
Receivables: | | | | | | | | |
Trade, net of allowance for doubtful accounts | | | 61,345 | | | | 26,648 | |
Unbilled receivables | | | 21,423 | | | | 8,586 | |
Insurance recoveries | | | 4,035 | | | | 5,107 | |
Income taxes | | | 2,712 | | | | 41,126 | |
Deferred income taxes | | | 9,867 | | | | 5,560 | |
Inventory | | | 9,023 | | | | 5,535 | |
Prepaid expenses and other current assets | | | 8,797 | | | | 6,199 | |
| | | | | | | | |
Total current assets | | | 151,782 | | | | 139,140 | |
| | | | | | | | |
Property and equipment, at cost | | | 1,097,179 | | | | 967,893 | |
Less accumulated depreciation | | | 441,671 | | | | 330,871 | |
| | | | | | | | |
Net property and equipment | | | 655,508 | | | | 637,022 | |
Intangible assets, net of amortization | | | 21,966 | | | | 25,393 | |
Noncurrent deferred income taxes | | | — | | | | 2,339 | |
Long-term investments | | | — | | | | 13,228 | |
Other long-term assets | | | 12,087 | | | | 7,833 | |
| | | | | | | | |
Total assets | | $ | 841,343 | | | $ | 824,955 | |
| | | | | | | | |
LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | | | |
Current liabilities: | | | | | | | | |
Accounts payable | | $ | 26,929 | | | $ | 15,324 | |
Current portion of long-term debt | | | 1,408 | | | | 4,041 | |
Prepaid drilling contracts | | | 3,669 | | | | 408 | |
Accrued expenses: | | | | | | | | |
Payroll and related employee costs | | | 18,057 | | | | 7,740 | |
Insurance premiums and deductibles | | | 8,774 | | | | 8,615 | |
Insurance claims and settlements | | | 4,035 | | | | 5,042 | |
Interest | | | 7,307 | | | | 271 | |
Other | | | 5,461 | | | | 7,363 | |
| | | | | | | | |
Total current liabilities | | | 75,640 | | | | 48,804 | |
Long-term debt, less current portion | | | 279,530 | | | | 258,073 | |
Other long-term liabilities | | | 9,680 | | | | 6,457 | |
Deferred income taxes | | | 80,160 | | | | 90,173 | |
| | | | | | | | |
Total liabilities | | | 445,010 | | | | 403,507 | |
| | | | | | | | |
Commitments and contingencies (Note 11) | | | | | | | | |
Shareholders’ equity: | | | | | | | | |
Preferred stock, 10,000,000 shares authorized; none issued and outstanding | | | — | | | | — | |
Common stock $.10 par value; 100,000,000 shares authorized; 54,228,170 shares and 54,120,852 shares issued and outstanding at December 31, 2010 and December 31, 2009, respectively | | | 5,425 | | | | 5,413 | |
Additional paid-in capital | | | 339,105 | | | | 332,534 | |
Treasury stock, at cost; 25,380 and 5,174 shares at December 31, 2010 and | | | | | | | | |
December 31, 2009, respectively | | | (161 | ) | | | (31 | ) |
Accumulated earnings | | | 51,964 | | | | 85,225 | |
Accumulated other comprehensive loss | | | — | | | | (1,693 | ) |
| | | | | | | | |
Total shareholders’ equity | | | 396,333 | | | | 421,448 | |
| | | | | | | | |
Total liabilities and shareholders’ equity | | $ | 841,343 | | | $ | 824,955 | |
| | | | | | | | |
STATEMENTS OF SHAREHOLDERS’ EQUITY
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Shares | | Amount | | Additional Paid In Capital | | Accumulated Earnings | | Total Shareholders' Equity |
| Common | | Treasury | Common | | Treasury |
| | (In thousands) |
| Balance as of December 31, 2010 | 54,253 |
| | (25 | ) | | $ | 5,425 |
| | $ | (161 | ) | | $ | 339,105 |
| | $ | 51,964 |
| | $ | 396,333 |
|
| Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 11,177 |
| | 11,177 |
|
| Sale of common stock, net of offering costs | 6,900 |
| | — |
| | 690 |
| | — |
| | 93,653 |
| | — |
| | 94,343 |
|
| Exercise of options and related income tax effect | 517 |
| | — |
| | 52 |
| | — |
| | 2,832 |
| | — |
| | 2,884 |
|
| Purchase of treasury stock | — |
| | (70 | ) | | — |
| | (743 | ) | | — |
| | — |
| | (743 | ) |
| Income tax effect of stock option forfeitures and expirations | — |
| | — |
| | — |
| | — |
| | (254 | ) | | — |
| | (254 | ) |
| Issuance of restricted stock | 207 |
| | — |
| | 21 |
| | — |
| | (21 | ) | | — |
| | — |
|
| Stock-based compensation expense | — |
| | — |
| | — |
| | — |
| | 6,705 |
| | — |
| | 6,705 |
|
| Balance as of December 31, 2011 | 61,877 |
| | (95 | ) | | $ | 6,188 |
| | $ | (904 | ) | | $ | 442,020 |
| | $ | 63,141 |
| | $ | 510,445 |
|
| Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 30,032 |
| | 30,032 |
|
| Exercise of options and related income tax effect | 172 |
| | — |
| | 17 |
| | — |
| | 676 |
| | — |
| | 693 |
|
| Purchase of treasury stock | — |
| | (40 | ) | | — |
| | (360 | ) | | — |
| | — |
| | (360 | ) |
| Income tax effect of stock option forfeitures and expirations | — |
| | — |
| | — |
| | — |
| | (449 | ) | | — |
| | (449 | ) |
| Issuance of restricted stock | 117 |
| | — |
| | 12 |
| | — |
| | (12 | ) | | — |
| | — |
|
| Stock-based compensation expense | — |
| | — |
| | — |
| | — |
| | 7,319 |
| | — |
| | 7,319 |
|
| Balance as of December 31, 2012 | 62,166 |
| | (135 | ) | | $ | 6,217 |
| | $ | (1,264 | ) | | $ | 449,554 |
| | $ | 93,173 |
| | $ | 547,680 |
|
| Net loss | — |
| | — |
| | — |
| | — |
| | — |
| | (35,932 | ) | | (35,932 | ) |
| Exercise of options and related income tax effect | 271 |
| | — |
| | 27 |
| | — |
| | 1,239 |
| | — |
| | 1,266 |
|
| Purchase of treasury stock | — |
| | (85 | ) | | — |
| | (631 | ) | | — |
| | — |
| | (631 | ) |
| Income tax effect of restricted stock vesting | — |
| | — |
| | — |
| | — |
| | (265 | ) | | — |
| | (265 | ) |
| Income tax effect of stock option forfeitures and expirations | — |
| | — |
| | — |
| | — |
| | (56 | ) | | — |
| | (56 | ) |
| Issuance of restricted stock | 316 |
| | — |
| | 31 |
| | — |
| | (31 | ) | | — |
| | — |
|
| Stock-based compensation expense | — |
| | — |
| | — |
| | — |
| | 6,371 |
| | — |
| | 6,371 |
|
| Balance as of December 31, 2013 | 62,753 |
| | (220 | ) | | $ | 6,275 |
| | $ | (1,895 | ) | | $ | 456,812 |
| | $ | 57,241 |
| | $ | 518,433 |
|
See accompanying notes to consolidated financial statements.
PIONEER DRILLING COMPANYENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATEDCONSOLIDATED STATEMENTS OF OPERATIONSCASH FLOWS
| | | | | | | | | | | | |
| | | Years ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (In thousands, except per share data) | |
Revenues: | | | | | | | | | | | | |
Drilling services | | $ | 312,196 | | | $ | 219,751 | | | $ | 456,890 | |
Production services | | | 175,014 | | | | 105,786 | | | | 153,994 | |
| | | | | | | | | | | | |
Total revenue | | | 487,210 | | | | 325,537 | | | | 610,884 | |
| | | | | | | | | | | | |
Costs and expenses: | | | | | | | | | | | | |
Drilling services | | | 227,136 | | | | 147,343 | | | | 269,846 | |
Production services | | | 105,295 | | | | 68,012 | | | | 80,097 | |
Depreciation and amortization | | | 120,811 | | | | 106,186 | | | | 88,145 | |
General and administrative | | | 52,047 | | | | 37,478 | | | | 44,834 | |
Bad debt (recovery) expense | | | 493 | | | | (1,642 | ) | | | 423 | |
Impairment of goodwill | | | — | | | | — | | | | 118,646 | |
Impairment of intangible assets | | | — | | | | — | | | | 52,847 | |
| | | | | | | | | | | | |
Total costs and expenses | | | 505,782 | | | | 357,377 | | | | 654,838 | |
| | | | | | | | | | | | |
Loss from operations | | | (18,572 | ) | | | (31,840 | ) | | | (43,954 | ) |
| | | | | | | | | | | | |
Other income (expense): | | | | | | | | | | | | |
Interest expense | | | (26,659 | ) | | | (9,145 | ) | | | (13,072 | ) |
Interest income | | | 92 | | | | 217 | | | | 1,256 | |
Impairment of investments | | | (3,331 | ) | | | — | | | | — | |
Other | | | 912 | | | | 596 | | | | (918 | ) |
| | | | | | | | | | | | |
Total other expense | | | (28,986 | ) | | | (8,332 | ) | | | (12,734 | ) |
| | | | | | | | | | | | |
Loss before income taxes | | | (47,558 | ) | | | (40,172 | ) | | | (56,688 | ) |
Income tax benefit (expense) | | | 14,297 | | | | 16,957 | | | | (6,057 | ) |
| | | | | | | | | | | | |
Net loss | | $ | (33,261 | ) | | $ | (23,215 | ) | | $ | (62,745 | ) |
| | | | | | | | | | | | |
Loss per common share—Basic | | $ | (0.62 | ) | | $ | (0.46 | ) | | $ | (1.26 | ) |
| | | | | | | | | | | | |
Loss per common share—Diluted | | $ | (0.62 | ) | | $ | (0.46 | ) | | $ | (1.26 | ) |
| | | | | | | | | | | | |
Weighted average number of shares outstanding—Basic | | | 53,797 | | | | 50,313 | | | | 49,789 | |
| | | | | | | | | | | | |
Weighted average number of shares outstanding—Diluted | | | 53,797 | | | | 50,313 | | | | 49,789 | |
| | | | | | | | | | | | |
|
| | | | | | | | | | | |
| | Year ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (In thousands) |
| Cash flows from operating activities: | | | | | |
| Net income (loss) | $ | (35,932 | ) | | $ | 30,032 |
| | $ | 11,177 |
|
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 187,918 |
| | 164,717 |
| | 132,832 |
|
| Allowance for doubtful accounts | 801 |
| | 76 |
| | 787 |
|
| (Gain) loss on dispositions of property and equipment | (1,421 | ) | | (1,199 | ) | | 151 |
|
| Stock-based compensation expense | 6,371 |
| | 7,319 |
| | 6,705 |
|
| Amortization of debt issuance costs, discount and premium | 3,095 |
| | 2,985 |
| | 3,302 |
|
| Impairment charges | 54,292 |
| | 1,131 |
| | 484 |
|
| Deferred income taxes | (22,125 | ) | | 13,303 |
| | 8,098 |
|
| Change in other long-term assets | (5,741 | ) | | (3,865 | ) | | 2,828 |
|
| Change in other long-term liabilities | (1,928 | ) | | (1,173 | ) | | (623 | ) |
| Changes in current assets and liabilities: | | | | | |
| Receivables | (16,168 | ) | | (12,807 | ) | | (46,802 | ) |
| Inventory | (1,121 | ) | | (927 | ) | | (2,161 | ) |
| Prepaid expenses and other current assets | 3,729 |
| | (1,266 | ) | | (1,965 | ) |
| Accounts payable | (166 | ) | | 2,431 |
| | 9,331 |
|
| Deferred revenues | (3,181 | ) | | (86 | ) | | 297 |
|
| Accrued expenses | 6,157 |
| | (1,305 | ) | | 20,438 |
|
| Net cash provided by operating activities | 174,580 |
| | 199,366 |
| | 144,879 |
|
| | | | | | |
| Cash flows from investing activities: | | | | | |
| Acquisition of production services business of Go-Coil | — |
| | — |
| | (109,035 | ) |
| Acquisition of other production services businesses | — |
| | — |
| | (6,502 | ) |
| Purchases of property and equipment | (165,356 | ) | | (364,324 | ) | | (210,066 | ) |
| Proceeds from sale of property and equipment | 13,836 |
| | 3,093 |
| | 5,550 |
|
| Proceeds from sale of auction rate securities | — |
| | — |
| | 12,569 |
|
| Proceeds from insurance recoveries | 844 |
| | — |
| | — |
|
| Net cash used in investing activities | (150,676 | ) | | (361,231 | ) | | (307,484 | ) |
| | | | | | |
| Cash flows from financing activities: | | | | | |
| Debt repayments | (60,874 | ) | | (874 | ) | | (113,158 | ) |
| Proceeds from issuance of debt | 40,000 |
| | 100,000 |
| | 250,750 |
|
| Debt issuance costs | (13 | ) | | (58 | ) | | (7,285 | ) |
| Proceeds from exercise of options | 1,266 |
| | 693 |
| | 2,884 |
|
| Proceeds from common stock, net of offering costs of $5,707 | — |
| | — |
| | 94,343 |
|
| Purchase of treasury stock | (631 | ) | | (360 | ) | | (743 | ) |
| Net cash provided by (used in) financing activities | (20,252 | ) | | 99,401 |
| | 226,791 |
|
| | | | | | |
| Net increase (decrease) in cash and cash equivalents | 3,652 |
| | (62,464 | ) | | 64,186 |
|
| Beginning cash and cash equivalents | 23,733 |
| | 86,197 |
| | 22,011 |
|
| Ending cash and cash equivalents | $ | 27,385 |
| | $ | 23,733 |
| | $ | 86,197 |
|
| | | | | | |
| Supplementary disclosure: | | | | | |
| Interest paid | $ | 46,274 |
| | $ | 44,317 |
| | $ | 26,955 |
|
| Income tax paid | $ | 3,154 |
| | $ | 731 |
| | $ | 952 |
|
See accompanying notes to consolidated financial statements.
PIONEER
DRILLING COMPANYENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Shares | | | Amount | | | Additional
Paid In
Capital | | | Accumulated
Earnings | | | Accumulated
Other
Comprehensive
Loss | | | Total
Shareholders’
Equity | |
| | Common | | | Treasury | | | Common | | | Treasury | | | | | |
| | | (In thousands) | |
Balance as of December 31, 2007 | | | 49,651 | | | | — | | | $ | 4,965 | | | $ | — | | | $ | 294,922 | | | $ | 171,185 | | | $ | — | | | $ | 471,072 | |
Comprehensive loss: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net loss | | | — | | | | — | | | | — | | | | — | | | | — | | | | (62,745 | ) | | | — | | | | (62,745 | ) |
Unrealized loss on securities | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (1,245 | ) | | | (1,245 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive loss | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (63,990 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Exercise of options and related income tax effect of $244 | | | 170 | | | | — | | | | 17 | | | | — | | | | 1,011 | | | | — | | | | — | | | | 1,028 | |
Issuance of restricted stock | | | 177 | | | | — | | | | 18 | | | | — | | | | (34 | ) | | | — | | | | — | | | | (16 | ) |
Stock-based compensation expense | | | — | | | | — | | | | — | | | | — | | | | 6,024 | | | | — | | | | — | | | | 6,024 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance as of December 31, 2008 | | | 49,998 | | | | — | | | $ | 5,000 | | | $ | — | | | $ | 301,923 | | | $ | 108,440 | | | $ | (1,245 | ) | | $ | 414,118 | |
Comprehensive loss: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net loss | | | — | | | | — | | | | — | | | | — | | | | — | | | | (23,215 | ) | | | — | | | | (23,215 | ) |
Unrealized loss on securities | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (448 | ) | | | (448 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive loss | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (23,663 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Sale of common stock, net of offering costs | | | 3,820 | | | | — | | | | 382 | | | | — | | | | 23,661 | | | | — | | | | — | | | | 24,043 | |
Purchase of treasury stock | | | — | | | | (5 | ) | | | — | | | | (31 | ) | | | — | | | | — | | | | — | | | | (31 | ) |
Income tax effect of restricted stock vesting | | | — | | | | — | | | | — | | | | — | | | | (235 | ) | | | — | | | | — | | | | (235 | ) |
Issuance of restricted stock | | | 308 | | | | — | | | | 31 | | | | — | | | | (31 | ) | | | — | | | | — | | | | — | |
Stock-based compensation expense | | | — | | | | — | | | | — | | | | — | | | | 7,216 | | | | — | | | | — | | | | 7,216 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance as of December 31, 2009 | | | 54,126 | | | | (5 | ) | | $ | 5,413 | | | $ | (31 | ) | | $ | 332,534 | | | $ | 85,225 | | | $ | (1,693 | ) | | $ | 421,448 | |
Comprehensive loss: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net loss | | | — | | | | — | | | | — | | | | — | | | | — | | | | (33,261 | ) | | | — | | | | (33,261 | ) |
Impact of impairment of investments charge | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1,693 | | | | 1,693 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive loss | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (31,568 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Exercise of options and related income tax effect of $16 | | | 63 | | | | — | | | | 6 | | | | — | | | | 248 | | | | — | | | | — | | | | 254 | |
Purchase of treasury stock | | | — | | | | (20 | ) | | | — | | | | (130 | ) | | | — | | | | — | | | | — | | | | (130 | ) |
Income tax effect of restricted stock vesting | | | | | | | | | | | | | | | | | | | (120 | ) | | | | | | | | | | | (120 | ) |
Income tax effect of stock option forfeitures and expirations | | | — | | | | — | | | | — | | | | — | | | | (226 | ) | | | — | | | | — | | | | (226 | ) |
Issuance of restricted stock | | | 64 | | | | — | | | | 6 | | | | — | | | | (6 | ) | | | — | | | | — | | | | — | |
Stock-based compensation expense | | | — | | | | — | | | | — | | | | — | | | | 6,675 | | | | — | | | | — | | | | 6,675 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance as of December 31, 2010 | | | 54,253 | | | | (25 | ) | | $ | 5,425 | | | $ | (161 | ) | | $ | 339,105 | | | $ | 51,964 | | | $ | — | | | $ | 396,333 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
See accompanying notes to consolidated financial statements.
PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | | | | | | | | | |
| | | Years ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (In thousands) | |
Cash flows from operating activities: | | | | | | | | | | | | |
Net loss | | $ | (33,261 | ) | | $ | (23,215 | ) | | $ | (62,745 | ) |
Adjustments to reconcile net loss to net cash provided by operating activities: | | | | | | | | | | | | |
Depreciation and amortization | | | 120,811 | | | | 106,186 | | | | 88,145 | |
Allowance for doubtful accounts | | | 521 | | | | (1,170 | ) | | | 1,591 | |
(Gain) loss on dispositions of property and equipment | | | (1,629 | ) | | | 56 | | | | (805 | ) |
Stock-based compensation expense | | | 6,675 | | | | 7,216 | | | | 4,597 | |
Amortization of debt issuance costs and discount | | | 2,609 | | | | 1,547 | | | | 553 | |
Impairment of investments | | | 3,331 | | | | — | | | | — | |
Impairment of goodwill and intangibles assets | | | — | | | | — | | | | 171,493 | |
Deferred income taxes | | | (13,224 | ) | | | 28,400 | | | | (2,066 | ) |
Change in other long-term assets | | | (1,373 | ) | | | 69 | | | | (288 | ) |
Change in non-current liabilities | | | 3,223 | | | | (1,312 | ) | | | (621 | ) |
Changes in current assets and liabilities: | | | | | | | | | | | | |
Receivables | | | (9,576 | ) | | | 18,180 | | | | (24,867 | ) |
Inventory | | | (3,487 | ) | | | (1,661 | ) | | | (927 | ) |
Prepaid expenses & other current assets | | | (2,598 | ) | | | 2,703 | | | | (2,390 | ) |
Accounts payable | | | 7,458 | | | | (2,243 | ) | | | (2,610 | ) |
Income tax payable | | | — | | | | — | | | | 409 | |
Prepaid drilling contracts | | | 3,261 | | | | (763 | ) | | | (762 | ) |
Accrued expenses | | | 15,610 | | | | (10,680 | ) | | | 17,928 | |
| | | | | | | | | | | | |
Net cash provided by operating activities | | | 98,351 | | | | 123,313 | | | | 186,635 | |
| | | | | | | | | | | | |
Cash flows from investing activities: | | | | | | | | | | | | |
Acquisition of production services business of WEDGE | | | — | | | | — | | | | (313,621 | ) |
Acquisition of production services business of Competition | | | — | | | | — | | | | (26,772 | ) |
Acquisition of other production services businesses | | | (1,340 | ) | | | — | | | | (9,301 | ) |
Purchases of property and equipment | | | (131,003 | ) | | | (114,712 | ) | | | (147,455 | ) |
Purchase of auction rate securities, net | | | — | | | | — | | | | (15,900 | ) |
Proceeds from sale of property and equipment | | | 2,331 | | | | 767 | | | | 4,008 | |
Proceeds from insurance recoveries | | | 531 | | | | 36 | | | | 3,426 | |
| | | | | | | | | | | | |
Net cash used in investing activities | | | (129,481 | ) | | | (113,909 | ) | | | (505,615 | ) |
| | | | | | | | | | | | |
Cash flows from financing activities: | | | | | | | | | | | | |
Debt repayments | | | (256,856 | ) | | | (17,298 | ) | | | (87,767 | ) |
Proceeds from issuance of debt | | | 274,375 | | | | — | | | | 359,400 | |
Debt issuance costs | | | (4,865 | ) | | | (2,560 | ) | | | (3,319 | ) |
Proceeds from exercise of options | | | 238 | | | | — | | | | 784 | |
Proceeds from common stock, net of offering costs of $454 | | | — | | | | 24,043 | | | | — | |
Purchase of treasury stock | | | (130 | ) | | | (31 | ) | | | — | |
| | | | | | | | | | | | |
Net cash provided by financing activities | | | 12,762 | | | | 4,154 | | | | 269,098 | |
| | | | | | | | | | | | |
Net (decrease) increase in cash and cash equivalents | | | (18,368 | ) | | | 13,558 | | | | (49,882 | ) |
Beginning cash and cash equivalents | | | 40,379 | | | | 26,821 | | | | 76,703 | |
| | | | | | | | | | | | |
Ending cash and cash equivalents | | $ | 22,011 | | | $ | 40,379 | | | $ | 26,821 | |
| | | | | | | | | | | | |
Supplementary disclosure: | | | | | | | | | | | | |
Interest paid | | $ | 17,529 | | | $ | 7,917 | | | $ | 12,468 | |
Income tax (refunded) paid | | $ | (39,778 | ) | | $ | (8,889 | ) | | $ | 11,767 | |
See accompanying notes to consolidated financial statements.
PIONEER DRILLING COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. | 1. Organization and Summary of Significant Accounting Policies
|
Business and PrinciplesSummary of Consolidation
Significant Accounting Policies
Business
Pioneer Drilling Company and subsidiaries provideEnergy Services provides drilling services and production services to our customers in selecta diverse group of independent and large oil and natural gas exploration and production companies throughout much of the onshore oil and gas producing regions inof the United States and internationally in Colombia. We also provide coiled tubing and wireline services offshore in the Gulf of Mexico.
Our Drilling Services DivisionSegment provides contract land drilling services with its fleet of 7162 drilling rigs inwhich are currently assigned to the following locations:divisions: | |
| | |
Drilling Division Locations | | Rig Count | |
South Texas | 14 | | 19 |
|
EastWest Texas
| 18 | | 13 |
|
West Texas
North Dakota | 11 | | 3 |
|
North Dakota
| | | 9 | |
North Texas
| | | 3 | |
Utah | | | 3 | |
Oklahoma
| | | 6 | |
Appalachia
| | | 7 |
|
Colombia
Appalachia | 4 |
|
| Colombia | 8 |
|
| 62 |
|
As
In early 2011, we began construction of February 4, 2011, 48 drilling rigs are operating under drilling contracts. We have 17ten new-build AC drilling rigs that are idle and sixfit for purpose for domestic shale plays, based on term contracts. We deployed seven of these new-build drilling rigs have been placedduring 2012, and deployed the final three in storage or “cold stacked” inearly 2013. All of our Oklahoma drilling division location due to low demand fornew-build drilling rigs are currently operating in that region. We are actively marketing all our idleshale or unconventional plays under long-term drilling rigs. contracts.
During the second quarter of 2009,2013, we established our Appalachia drilling division location and now have seven drilling rigs operating in the Marcellus Shale. In early 2011, we established our West Texas drilling division location with threesold two mechanical drilling rigs that were previously includedidle in our East Texas division, for which we recognized an associated gain of approximately $0.8 million. In September 2013, we decided to sell eight of our mechanical drilling division location. Onerigs, for which we recognized an impairment charge of $9.2 million dollars during the third quarter. All eight drilling rigs were classified as held for sale at September 30, 2013 and were sold in late October 2013. We did not incur any additional gain or loss upon the sale of these rigs.
As of December 31, 2013, 50 of our 62 drilling rigs has begunare earning revenues under drilling in the Permian Basincontracts, 39 of which are under term contracts, and we are actively marketing all of our idle drilling rigs. All eight of our drilling rigs in Colombia are currently under term contracts that extend through the end of 2014, seven of which are currently working. The remaining rig will begin working under its term contract after it is upgraded from 1,000 horsepower to 1,500 horsepower, which we expect will be completed by the remaining two rigs to begin operations in late February 2011. end of the first quarter of 2014.
In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with customers.existing or potential clients. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, and the anticipated duration of the work to be performed. Our Production Services DivisionSegment provides a range of services to exploration and production companies, including well servicing, wireline services, wirelinecoiled tubing services, and fishing and rental services. Our production services operations are managed through locations concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, Mid-Continent, Rocky Mountainboth onshore and Appalachian states.offshore. As of February 4, 2011,December 31, 2013, we have a premium fleet of 75109 well serviceservicing rigs consisting of seventyninety-nine 550 horsepower rigs fourand ten 600 horsepower
rigs,
and one 400 horsepower rig. All our well service rigsall of which are currently operating or are being actively
marketed, with January 2011 utilization of approximately 88%.marketed. We currently provide wireline services
and coiled tubing services with a fleet of
86119 wireline units and
13 coiled tubing units, and we provide rental services with
approximately $13.5a gross book value of $17.3 million
ofin fishing and rental tools.
We plan to add another five well service rigs and 12 wireline units to our production services fleet by mid-2011.Basis of Presentation
The accompanying consolidated financial statements include the accounts of Pioneer Drilling CompanyEnergy Services Corp. and our wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America.
In preparing the accompanying consolidated financial statements, we make various estimates and assumptions that affect the amounts of assetsand liabilities we report as of the dates of the balance sheets and income and expenses we report for the periods shown in the income statements and statements of cash flows. Our actual results could differ significantly from those estimates.
Material estimates that are particularly susceptible to significant changes in the near term relate to our recognition of revenues and costs for turnkey contracts, our estimate of the allowance for doubtful accounts, our determination of depreciation and amortization expenses, our estimates of fair value for impairment evaluations, our estimate of deferred taxes, our estimate of the liability relating to the self-insurance portion of our health and workers’ compensation insurance, our estimate of asset impairments, our estimate of deferred taxes,and our estimate of compensation related accruals and our determination of depreciation and amortization expense.accruals.
In preparing the accompanying consolidated financial statements, we have reviewed events that have occurred after December 31,
2010,2013, through the filing of this Form 10-K, for inclusion as necessary.
Recently Issued Accounting Standards
Multiple Deliverable Revenue Arrangements.In October 2009, the FASB issued Accounting Standards Update (ASU) No. 2009-13, Revenue Recognition (Topic 605):Multiple Deliverable Revenue Arrangements—A Consensus of the FASB Emerging Issues Task Force.This update provides application guidance on whether multiple deliverables exist, how the deliverables should be separated and how the consideration should be allocated to one or more units of accounting. This update establishes a selling price hierarchy for determining the selling price of a deliverable. The selling price used for each deliverable will be based on vendor-specific objective evidence, if available, third-party evidence if vendor-specific objective evidence is not available, or estimated selling price if neither vendor-specific or third-party evidence is available. We will be required to apply this guidance prospectively for revenue arrangements entered into or materially modified after January 1, 2011; however, earlier application is permitted. We do not expect the adoption of this new guidance to have a material impact on our financial position or results of operations.
Business Combinations. In December 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-29, Business Combinations (Topic 805):Disclosure of Supplementary Pro Forma Information for Business Combinations—A consensus of the FASB Emerging Issues Task Force. This update provides clarification requiring public companies that have completed material acquisitions to disclose the revenue and earnings of the combined business as if the acquisition took place at the beginning of the comparable prior annual reporting period, and also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. We will be required to apply this guidance prospectively for business combinations for which the acquisition date is on or after January 1, 2011. We do not expect the adoption of this new guidance to have a material impact on our financial position or results of operations.
Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, and the anticipated duration of the work to be performed.
Generally, ourSpot market contracts
generally provide for the drilling of a single well and typically permit the
customerclient to terminate on short notice.
However, we have entered into more longer-term drilling contracts duringDuring periods of high rig
demand. In addition, we have entered into longer-term drilling contractsdemand, or for our newly constructed
rigs.rigs, we enter into longer-term drilling contracts. Currently, we have
32 contracts with terms of six months to
threefour years in duration.
Of these 32As of December 31, 2013, we have 39 drilling rigs operating under term contracts,
which if not renewed at the end of their terms,
14 will expire
by August 15, 2011, 11 will expire by February 15, 2012, one will expire by August 15, 2012 and six have a remaining term in excess of 18 months. We have one additional drilling rig under contract that we expect will begin operating in late February 2011 with a six month term.as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | | | Term Contract Expiration by Period |
| | | Total Term Contracts | | Within 6 Months | | 6 Months to 1 Year | | 1 Year to 18 Months | | 18 Months to 2 Years | | 2 to 4 Years |
| United States | | 33 |
| | 18 |
| | 4 |
| | 5 |
| | 1 |
| | 5 |
|
| Colombia | | 6 |
| | — |
| | 6 |
| | — |
| | — |
| | — |
|
| | | 39 |
| | 18 |
| | 10 |
| | 5 |
| | 1 |
| | 5 |
|
Our functional currency for our foreign subsidiary in Colombia is the U.S. dollar. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in
effect at the end of the period. Income statement accounts are translated at average rates for the period. Gains and losses from remeasurement of foreign currency financial statements into U.S. dollars and from foreign currency transactions are included in other income or expense.
Revenue and Cost Recognition
Drilling Services—We earnOur Drilling Services Segment earns revenues by drilling oil and natural gas wells for our customersclients under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. Drilling contracts for individual wells are usually completed in less than60days. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each contract. With most drilling contracts, we receive payments contractually designated for the mobilizationAll our revenues are recognized net of rigs and other equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on a straight line basis over the related contract term. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses are recorded as revenue and the out-of-pocket expenses for which they relate are recorded as operating costs.applicable sales taxes.
Our management has determined that it is appropriate to use the percentage-of-completion method as defined in the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 605,Revenue Recognition, to recognize revenue on our turnkey and footage contracts. Although our turnkey and footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed-on depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and we believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed-on depth in breach of the applicable contract. However, in the event we were unable to drill to the agreed-on depth in breach of the contract, ultimate recovery of that value would be subject to negotiations with the customerclient and the possibility of litigation. If a customerclient defaults on its payment obligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and footage contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed-on depth in breach of the contract, we also would need to rely on equitable remedies outside of the contract available in applicable courts to recover the fair value of our work-in-progress under a turnkey or footage contract. The risks to us under a turnkey contract and, to a lesser extent, under footage contracts, are substantially greater than on a contract drilled on a daywork basis. Under a turnkey contract, we assume most of the risks associated with drilling operations that are generally assumed by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors’ services, supplies, cost escalations and personnel operations.
We accrue estimated contract costs on turnkey and footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance, operating overhead allocations and allocations of depreciation and amortization expense. We charge generalIn addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and administrative expenses to expense as we incur them. Changes in job performance, job conditionsfootage contracts could have a material adverse effect on our financial position and estimated profitability on uncompleted contracts may result in revisions to costs and income. When we encounter, during the courseresults of operations. Therefore, our drilling operations, conditions unforeseen in the preparation ofactual results for a contract could differ significantly if our cost estimates for that contract are later revised from our original cost estimate, we immediately increase our cost estimateestimates for the additional costs to complete the contract. If we anticipate a loss on a contract in progress at the end of a reporting period duewhich was not completed prior to a change inthe release of our cost estimate, we immediately accrue the entire amount of the estimated loss including all costs that are included in our revised estimated cost to complete that contract in our consolidated statement of operations for that reporting period. We had one turnkey and no footage contracts in progress as of December 31, 2010.financial statements
Production Services—We earn revenues for well services, wireline services and fishing and rental services based on purchase orders, contracts or other persuasive evidence of an arrangement with the customer, such as master service agreements, that include fixed or determinable prices. These production services revenues are recognized when the services have been rendered and collectability is reasonably assured..The asset “unbilled receivables” represents revenues we have recognized in excess of amounts billed on
With most drilling contracts, we receive payments contractually designated for the mobilization of rigs and other equipment. Payments received, and costs incurred for productionthe mobilization services completed butare deferred and recognized on a straight line basis over the related contract term. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not yet invoiced. been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses are recorded as revenue and the out-of-pocket expenses for which they relate are recorded as operating costs.
The assets “prepaid expenses and other current assets” and “other long-term assets” include the current and long-term portions of deferred mobilization costs for certain drilling contracts. The liabilities “prepaid drilling contracts”“deferred revenues” and “other long-term liabilities” include the current and long-term portions of deferred mobilization revenues for certain drilling contracts and amounts collected on contracts in excess of revenues recognized. As ofDecember 31, 2010 2013we had $6.3$0.7 millionand $0.9 millionof current deferred mobilization revenues and costs, respectively, and $0.4 millionand$0.5 millionof which the current portion was $3.7 million. The relatedlong-term deferred mobilization revenues and costs, were $5.8 million, of which the current portion was $3.3 million.respectively. Our deferred mobilization costs and revenues primarily related to long-term contracts for our Colombian operations,new-build drilling rigs and long-term contracts for drilling rigs which are being amortized through the year ending December 31, 2012.we moved between drilling divisions. Amortization of deferred mobilization revenues was $3.0$5.3 million, $6.3 million and $5.1 million for the year yearsendedDecember 31, 2010.2013
, 2012 and 2011, respectively. Production Services—Our Production Services Segment earns revenues for well servicing, wireline services, coiled tubing services and fishing and rental services pursuant to master services agreements based on purchase orders, contracts or other arrangements with the client that include fixed or determinable prices. Production services jobs are generally short-term and are charged at current market rates. Production service revenue is recognized when the service has been rendered and collectability is reasonably assured.
Cash and Cash Equivalents
For purposes of the statements of cash flows, we consider all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Cash equivalents consist of investments in corporate and government money market accounts. Cash equivalents at December 31, 20102013 and 20092012 were $5.7 million and $9.9 million, respectively.Restricted Cash
As of December 31, 2010, we had restricted cash in the amount of $2.0 million held in an escrow account to be used for future payments in connection with the acquisition of Prairie Investors d/b/a Competition Wireline (“Competition”). The former owner of Competition will receive annual installments of $0.7 million payable over the remaining three years from the escrow account. Restricted cash of $0.7 million and $1.3$3.1 million, is recorded in other current assets and other long-term assets, respectively. The associated obligation of $0.7 million and $1.3 million is recorded in accrued expenses and other long-term liabilities, respectively.
Trade Accounts Receivable
We record trade accounts receivable at the amount we invoice our customers.clients. These accounts do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our accounts receivable as of the balance sheet date. We determine the allowance based on the credit worthiness of our customersclients and general economic conditions. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts.
We review our allowance for doubtful accounts on a monthly basis.
Our typical drilling contract provides for payment of invoices in 30 days. We generally do not extend payment terms beyond 30 days and have not extended payment terms beyond 90 days for any of our contracts in the last three fiscal years. Our production services terms generally provide for payment of invoices in 30 days. Balances more than 90 days past due are reviewed individually for collectability. We charge off account balances against the allowance after we have exhausted all reasonable means of collection and determined that the potential for recovery is remote. We do not have any off-balance sheet credit exposure related to our
customers.clients.
The changes in our allowance for doubtful accounts consist of the following (amounts in thousands):
| | | | | | | | | | | | |
| | | Years ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
Balance at beginning of year | | $ | 286 | | | $ | 1,574 | | | $ | — | |
Increase (decrease) in allowance charged to expense | | | 521 | | | | (1,170 | ) | | | 1,591 | |
Accounts charged against the allowance, net of recoveries | | | (95 | ) | | | (118 | ) | | | (17 | ) |
| | | | | | | | | | | | |
Balance at end of year | | $ | 712 | | | $ | 286 | | | $ | 1,574 | |
| | | | | | | | | | | | |
|
| | | | | | | | | | | |
| | Year ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Balance at beginning of year | $ | 1,044 |
| | $ | 994 |
| | $ | 712 |
|
| Increase in allowance charged to expense | 801 |
| | 76 |
| | 787 |
|
| Accounts charged against the allowance, net of recoveries | (489 | ) | | (26 | ) | | (505 | ) |
| Balance at end of year | $ | 1,356 |
| | $ | 1,044 |
| | $ | 994 |
|
Unbilled Accounts Receivable
The asset “unbilled receivables” represents revenues we have recognized in excess of amounts billed on drilling contracts and production services completed but not yet invoiced. We typically invoice our clients at 15-day intervals during the performance of daywork drilling contracts and upon completion of the daywork contract. Turnkey and footage drilling contracts are invoiced upon completion of the contract.
Our unbilled receivables totaled $49.5 millionat December 31, 2013, of which $45.4 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at December 31, 2013 and $4.1 million related to unbilled receivables for our Production Services Segment.
Inventories
Inventories primarily consist of drilling rig replacement parts and supplies held for use by our Drilling Services Segment’s operations in Colombia and supplies held for use by our Production Services Segment’s operations. Inventories are valued at the lower of cost (first in, first out or actual) or market value.
Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets include items such as insurance, rent deposits and
fees, and restricted cash.fees. We routinely expense these items in the normal course of business over the periods these expenses benefit. Prepaid expenses and other current assets also include
the current portion of deferred mobilization costs for certain drilling contracts that are recognized on a
straight linestraight-line basis over the contract term.
Investments
InvestmentsAs of December 31, 2010, short-term investments represented tax exempt, auction rate preferred securities (“ARPS”) that were classified as available for sale. The ARPSs were liquidated subsequent to year end on January 19, 2011. As of December 31, 2009 and 2008, the ARPSs were classified as long-term investments because of our inability to determine the recovery period of these available for sale investments at those times.
At December 31, 2010, we held $15.9 million (par value) of ARPSs,auction rate preferred securities (“ARPSs”), which were variable-rate preferred securities and hadwith a long-term maturity with the interest rate being reset through “Dutch auctions” that were classified as held every seven days. The ARPSs had historically traded at par because of the frequent interest rate resets and because they were callable at par at the option of the issuer. Interest was paid at the end of each auction period. Our ARPSs were AAA/Aaa rated securities, collateralized by municipal bonds and backed by assets that were equal to or greater than 200% of the liquidation preference. Until February 2008, the auction rate securities market was highly liquid. Beginning mid-February 2008, we experienced several “failed” auctions, meaning that there was not enough demand to sell all of the securities that holders desired to sell at auction. The immediate effect of a failed auction was that such holders could not sell the securities at auction and the interest rate on the security reset to a maximum auction rate. We continued to receive interest payments on our ARPSs in accordance with their terms.
for sale. On January 19, 2011, we entered into an agreement with a financial institution to sell the ARPSs for $12.6 million, which representsrepresented 79% of the par value, plus accrued interest. The $3.3 million difference between the ARPSs’ par value of $15.9 million and the sales price of $12.6 million represented an other-than-temporary impairment of the ARPSs investment which was reflected as an impairment of investments in our consolidated statement of operations for the year ended December 31, 2010.
Under the
ARPSs sales agreement, we retained the unilateral right for a period ending January 7, 2013 to: (a) repurchase all the ARPSs that were sold at the $12.6 million price at which they were initially sold to the financial institution; and (b) if not repurchased, receive additional proceeds from the financial institution upon redemption of the ARPSs by the original issuer of these securities (collectively, the “ARPSs Call Option”).
The ARPSs Call Option has an estimated fair value of $0.6 million which will be recognized in our consolidated financial statements in 2011.Our ARPSs were reported at amounts that reflected our estimate of fair value. ASC Topic 820,Fair Value Measurements and Disclosures (“ASC Topic 820”), provides a hierarchal framework associated with the level of subjectivity used in measuring assets and liabilities at fair value:
To estimate the fair values of our ARPSs as of December 31, 2010, we used inputs defined by ASC Topic 820 as level 1 inputs which are quoted market prices in active markets for identical securities. We obtained a quoted market price and liquidated the ARPSs subsequent to year end on January 19, 2011 based on the terms of the settlement agreement noted above. Therefore, the sales price under the settlement agreement of $12.6 million representsUpon origination, the fair value of the ARPSs at December 31, 2010. The $3.3 million difference between the ARPSs’ par value of $15.9Call Option was estimated to be $0.6 million and was recognized as other income in our consolidated statement of operations for 2011. The ARPSs Call Option was subsequently carried at fair value on our consolidated balance sheets with changes in fair value recognized as "other income (loss)" in our consolidated statement of operations.
On October 1, 2012, we received proceeds of $0.6 million from the sales priceredemption of $12.6 million represents an other-than-temporary impairmentcertain ARPSs by the original issuer of the ARPSs investmentsecurities, which is reflectedwe recognized as an impairment of investmentsother income in our consolidated statement of operations for the year ended December 31, 2010. During the years ended December 31, 2009 and 2008, $2.7 million of the difference between the par value and2012. The ARPSs Call Option had a fair value of the ARPSs was considered temporary and was recorded as unrealized losses, net of tax, in accumulated other comprehensive income (loss) which is a component of shareholders’ equity.
To estimate the fair values of our ARPSszero as of December 31, 20092012 and 2008, we used inputs defined by ASC Topic 820 as level 3 inputs which are unobservable for the asset or liability and are developed
expired on January 7, 2013. | based on the best information available in the circumstances. We estimated the fair value of our ARPSs based on discounted cash flow models and secondary market comparisons of similar securities. Based on this methodology, the estimated fair value of our ARPSs was $13.2 million at December 31, 2009 and $13.9 million at December 31, 2008, as compared to the par value of $15.9 million at both December 31, 2009 and December 31, 2008. The differences between the ARPSs’ fair values and par values were due to the lack of liquidity which was considered to be temporary at that time. We believed we would ultimately recover the par value of the ARPSs without a loss, primarily due to the collateral securing the ARPSs and our estimate of the discounted cash flows that we expected to collect. Also, we did not intend to sell the ARPSs at a loss and we believed it was more-likely-than-not that we would not have to sell prior to recovery of the ARPSs’ par value based on our liquidity needs. Therefore, the fair value discounts of $2.7 million and $2.0 million at December 31, 2009 and 2008, respectively, were recorded as unrealized losses, net of tax, in accumulated other comprehensive income (loss) which was a component of shareholders’ equity. There were no portions of the fair value discounts attributable to credit losses.
|
Inventories
Inventories primarily consist of drilling rig replacement parts and supplies held for use by our Drilling Services Division’s operations in Colombia and supplies held for use by our Production Services Division’s operations. Inventories are valued at the lower of cost (first in, first out or actual) or market value.
Property and equipment are carried at cost less accumulated depreciation. Depreciation is provided for our assets over the estimated useful lives of the assets using the straight-line method. We record the same depreciation expense whether a rig is idle or working. We charge our expenses for maintenance and repairs to operating costs. We
charge our expensescapitalize expenditures for renewals and betterments to the appropriate property and equipment accounts.
As of December 31, 2010, the estimated useful lives and costs of our asset classes are as follows:
| | | | | | |
| | | Lives | | Cost | |
| | | | | (amounts in thousands) | |
Drilling rigs and equipment | | 3 - 25 | | $ | 846,443 | |
Workover rigs and equipment | | 5 - 20 | | | 123,831 | |
Wireline units and equipment | | 2 - 10 | | | 66,452 | |
Fishing and rental tools equipment | | 7 | | | 13,515 | |
Vehicles | | 3 - 10 | | | 34,177 | |
Office equipment | | 3 - 5 | | | 5,162 | |
Buildings and improvements | | 3 - 40 | | | 6,991 | |
Land | | — | | | 608 | |
| | | | | | |
| | | | $ | 1,097,179 | |
| | | | | | |
We recorded gains (losses) on disposition of our property and equipment in contract drilling costs of $1.6 million, ($0.1) million and $0.8 million for the years ended December 31, 2010, 2009 and 2008, respectively. During the years ended December 31, 2010, 2009 and 2008, we capitalized $0.5 million, $0.3 million and $0.3 million, respectively, of interest costs incurred during the construction periods of certain drilling equipment. We had no drilling rigs under construction at December 31, 2010.
We evaluate for potential impairment of long-lived assetstangible and intangible assets subject to amortization when indicators of impairment are present, as defined in ASC Topic 360,Property, Plant, and Equipment (“ASC Topic360”) and ASC Topic 350,Intangibles—Goodwill and Other (“ASC Topic 350”).present. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts for drilling rigs and well serviceservicing rigs. In performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of long-lived assetstangible and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services Division, our long-lived assetsSegment, we perform an impairment evaluation and intangible assets are grouped atestimate future undiscounted cash flows for the individual reporting unit level which is one level below the operating segment level. units (well servicing, wireline, coiled tubing and fishing and rental services).For our Drilling Services Division,Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual drilling rig assets.If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the long-lived assets and intangible assets for these asset grouping levels,group, then we would recognize an impairment charge.determine the fair value of the asset group. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. As describedThe assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management judgment.
Intangible Asset sectionAssets
Our intangible assets consist of Note 1,the following components as of December 31, 2013 and 2012 (amounts in thousands):
|
| | | | | | | |
| | December 31, |
| | 2013 | | 2012 |
| Cost: | | | |
| Client relationships | $ | 63,168 |
| | $ | 66,273 |
|
| Non-compete agreements | 1,355 |
| | 1,355 |
|
| Trademarks / trade names | 575 |
| | 568 |
|
| Accumulated amortization: | | | |
| Client relationships | (31,584 | ) | | (23,667 | ) |
| Non-compete agreements | (745 | ) | | (436 | ) |
| Trademarks / trade names | (500 | ) | | (250 | ) |
| | $ | 32,269 |
| | $ | 43,843 |
|
Substantially all of our intangible assets were recorded in connection with the acquisitions of production services businesses and are subject to amortization. The cost of our client relationships, trademarks and trade names are amortized using the straight-line method over their respective estimated economic useful lives which range from two to nine years. Amortization expense for our non-compete agreements is calculated using the straight-line method over the period of the agreements which range from three to seven years. Amortization expense was $8.5 million, $8.7 million and $4.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. Amortization expense is estimated to be approximately $8.0 million, $7.9 million, $5.1 million, $3.8 million and $3.8 million for the years ending December 31, 2014, 2015, 2016, 2017 and 2018, respectively. Actual amortization amounts may be different due to future acquisitions, impairments, changes in amortization periods, or other factors.
We evaluate for potential impairment of long-lived assettangible and intangible assetassets subject to amortization when indicators of impairment analysisare present. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts for drilling rigs and well servicing rigs. In performing an impairment evaluation, we estimate the reporting units infuture undiscounted net cash flows from the use and eventual disposition of long-lived tangible and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services DivisionSegment, we perform an impairment evaluation and estimate future undiscounted cash flows for the individual reporting units (well servicing, wireline, coiled tubing and fishing and rental services).If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the asset group, then we would determine the fair value of the asset group. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management judgment.
Due to several significant adverse factors affecting our coiled tubing services reporting unit, including increased competition in certain coiled tubing markets, turnover of key personnel and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of ourlong-lived tangible and intangible assets as of June 30, 2013. We determined that the sum of the estimated future undiscounted net cash flows for our coiled tubing services reporting unit was less than the carrying amount at June 30, 2013. We then performed a valuation of the assets which resulted in no impairment charge to property and equipment and a non-cash impairment charge of $52.8$3.1 millionto thereduce our intangible asset carrying value of our intangible assets for customers relationships for the year ended December 31, 2008. client relationships.This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the overall downturnincreased competition in our industrycertain coiled tubing markets where we operate and a decline in our projected cash flows. We did not record anflows for the coiled tubing reporting unit.
The most significant inputs used in our impairment analysis include the projected utilization and pricing of our coiled tubing services, which are classified as Level 3 inputs as defined by ASC Topic 820,Fair Value Measurements and Disclosures.An increase of 1% in either the utilization or pricing assumptions would have resulted in a decrease to our impairment charge on any long-lived assets for our Production Services Division forlong-lived intangible assets of approximately $1 million. Similarly, a decrease of 1% in either of these assumptions would have led to an approximate $1 million increase to our impairment charge. Although we believe the years ended December 31, 2010 or 2009. Forassumptions and estimates used in our Drilling Services Division, we did not record an impairment charge on any long-lived assets foranalysis are reasonable and appropriate, different assumptions and estimates could materially impact the years ended December 31, 2010, 2009 or 2008.analysis and resulting conclusions. The assumptions used in estimating fair values and performing the impairment evaluation for long-lived assets and intangible assetstest are inherently uncertain and require management judgment. As of December 31, 2013, our carrying value of intangible assets related to the acquisition of Go-Coil was $21.8 million. Due to continued increases in competition in certain coiled tubing markets and lower than anticipated operating results, we performed another impairment analysis of our long-lived tangible and intangible assets as of December 31, 2013. We determined that the sum of the estimated future undiscounted net cash flows for our coiled tubing services reporting unit was in excess of the carrying amount and concluded that no impairment existed as of December 31, 2013. The future undiscounted cash flows used in our impairment analysis include projected increases in utilization and pricing from what we have historically experienced. If we fail to meet the projected increases in utilization and pricing for our coiled tubing services, or in the event of significant unfavorable changes in the forecasted cash flows or key assumptions used in our analysis, the most significant of these being the projected utilization and pricing of our coiled tubing services, then we may incur a future impairment.
Our impairment analysis did not result in any impairment charges to our coiled tubing tangible long-lived assets, substantially all of which was related to the 13 coiled tubing units. As discussed further below, we also recorded a non-cash impairment charge to reduce the carrying value of goodwill to zero.
Goodwill results from business acquisitions and represents the excess of acquisition costs over the fair value of the net assets acquired. In connection with the acquisition of the production services business from Go-Coil, we recorded $41.7 million of goodwill at December 31, 2011, all of which was allocated to the coiled tubing services reporting unit within our Production Services Segment.
We account forperform a qualitative assessment of goodwill and other intangible assets under the provisions of ASC Topic 350. Goodwill is tested for impairment annually as of December 31 or more frequently if events or changes in circumstances indicate that the asset might be impaired. Circumstances that could indicate a potential impairment include a significant adverse change in the economic or business climate, a significant adverse change in legal factors, an adverse action or assessment by a regulator, unanticipated competition, loss of key personnel and the likelihood that a reporting unit or significant portion of a reporting unit will be sold or otherwise disposed of. TheseIn addition, these circumstances could lead to our net book value exceeding our market capitalization which is another indicator of a potential impairment inof goodwill. ASC Topic 350 requires
If our qualitative assessment of goodwill indicates a possible impairment, we test for goodwill impairment using a two-step process for testing impairment.process. First, the fair value of each reporting unit with goodwill is compared to its carrying value to determine whether an indication of impairment exists. All our goodwill was related to our Production Services Division operating segment and was allocated to its three reporting units which are well services, wireline services and fishing and rental services. Second, if impairment is indicated, then the fair value of the reporting unit's goodwill is determined by allocating the unit's fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination on the
impairment test date. The amount of impairment for goodwill is measured as the excess of the carrying value of the reporting unit over its fair value. Goodwill of $118.6 million was initially recorded in connection with the acquisitions of the production services businesses from WEDGE, Competition, Pettus and Paltec, all of which occurred between March 1, 2008 and October 1, 2008, and was allocated to the three reporting units for our Production Services Division which are well services, wireline services and fishing and rental services. We recorded a full impairment of this goodwill during the year ended December 31, 2008 as further described below.
When estimating fair values of a reporting unit for our goodwill impairment test, we use a combination of an income approach and a market approach which incorporates both management’s views and those of the market. The income approach provides an estimated fair value based on eachthe reporting unit’s anticipated cash flows that wereare discounted using a weighted average cost of capital rate. The market approach provides anestimated fair value based on our market capitalization that was computed using the prior 30-day average market price of our common stock and the number of shares outstanding as of the impairment test date. The estimated fair values computed using the income approach and the market approach were then equally weighted and combined into a single fair value. The primary assumptions used in the income approach wereare estimated cash flows and weighted average cost of capital. Estimated cash flows wereare primarily based on projected revenues, operating costs and capital expenditures and are discounted at a rate that is based on comparable industry average rates for weighted average cost of capital. We utilized discount rates based onour weighted average cost of capital ranging from 15.8% to 16.7% when weand estimated fair valuesindustry average rates for cost of our reporting units as of December 31, 2008. The primary assumptions used in the market approach were the allocation of total market capitalization to each reporting unit, which was based on projected EBITDA percentages for each reporting unit, and control premiums, which were based on comparable industry averages. We utilized a 30% control premium when we estimated fair values of our reporting units as of December 31, 2008.capital. To ensure the reasonableness of the estimated fair valuesvalue of our reporting units, we performedconsider current industry market multiples and we perform a reconciliation of our total market capitalization to the total estimated fair value of all our reporting units. The assumptions used
Due to several significant adverse factors affecting our coiled tubing services reporting unit, including increased competition in estimatingcertain coiled tubing markets, turnover of key personnel and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of ourgoodwill as of June 30, 2013. We determined that the fair valuesvalue of our coiled tubing services reporting unitsunit was less than its carrying value, including goodwill, and performingtherefore, we performed the second step of the goodwill impairment test are inherently uncertain and required management judgment.Our common stock price per share declined in market value from $13.30 at September 30, 2008, to $5.57 at December 31, 2008, which resulted in our net book value exceeding our market capitalization during most of that time period. We concluded that the decline in the market price of our common stock resulted from a significant adverse change in the economic and business climate as financial markets reacted to the credit crisis facing major lending institutions and worsening conditions in the overall economy during the fourth quarter of the year ended December 31, 2008. During the same time, there were significant declines in oil and natural gas prices which led to declines in production service revenues, margins and cash flows. We considered the impact of these significant adverse changes in the economic and business climate as we performed our annual impairment assessment of goodwill as of December 31, 2008. The estimated fair values of our reporting units were negatively impacted by significant reductions in estimated cash flows for the income approach component and a significant reduction in our market capitalization for the market approach component of our fair value estimation process. Our goodwill was initially recorded in connection with the acquisitions of the production services businesses from WEDGE, Competition, Pettus and Paltec, all of which occurred between March 1, 2008 and October 1, 2008, when production service revenues, margins and cash flows and our market capitalization were at historically high levels.
Our goodwill impairment analysis led us to conclude that there would be no remaining implied fair value attributable to our goodwill and, accordingly,goodwill. Accordingly, we recorded a non-cash impairment charge of $118.6
$41.7 millionto our operating results forreduce the year ended December 31, 2008, for the full impairmentcarrying value of our goodwill. Our goodwill impairment analysis would have led to the same full impairment conclusion if we increased or decreased our discount rates or control premiums by 10% when estimating the fair values of our reporting units. zero.This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the overall downturnincreased competition in our industrycertain coiled tubing markets where we operate and a decline in our projected cash flows.Changesflows for the coiled tubing reporting unit.
The most significant inputs used in our impairment analysis include the carrying amount of goodwill by operating segment are as follows (amounts in thousands): | | | | | | | | | | | | |
| | | Drilling
Services
Division | | | Production
Services
Division | | | Total | |
Goodwill balance at January 1, 2008 | | $ | — | | | $ | — | | | $ | — | |
Goodwill relating to acquisitions | | | — | | | | 118,646 | | | | 118,646 | |
Impairment | | | — | | | | (118,646 | ) | | | (118,646 | ) |
| | | | | | | | | | | | |
Goodwill balance at December 31, 2008 | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | |
We had no goodwill additions during the years ended December 31, 2010 or 2009,projected utilization and consequently, have no goodwill reflected on our consolidated balance sheets at December 31, 2010 and 2009.
Intangible Assets
All our intangible assets are subject to amortization and consist of customers relationships, non-compete agreements and trade names. Essentially allpricing of our intangible assets were recordedcoiled tubing services and the weighted average cost of capital (discount rate) used in connection withorder to calculate the acquisitions ofdiscounted cash flows for the production services businesses from WEDGE, Competition, Pettus, Paltec and Tiger, all of whichreporting unit. These inputs are described in Note 2. Intangible assets consist of the following components (amounts in thousands):
| | | | | | | | |
| | | December 31,
2010 | | | December 31,
2009 | |
Cost: | | | | | | | | |
Customer Relationships | | $ | 33,036 | | | $ | 32,039 | |
Non-compete | | | 2,024 | | | | 2,304 | |
Trade marks | | | 155 | | | | 143 | |
Accumulated amortization: | | | | | | | | |
Customer Relationships | | | (11,462 | ) | | | (7,509 | ) |
Non-compete | | | (1,787 | ) | | | (1,584 | ) |
| | | | | | | | |
| | $ | 21,966 | | | $ | 25,393 | |
| | | | | | | | |
We evaluate for potential impairment of long-lived assets and intangible assets subject to amortization when indicators of impairment are present,classified as Level 3 inputs as defined inby ASC Topic 360820,
Fair Value Measurements and ASC Topic 350. Circumstances that could indicateDisclosures.We assumed a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts for drilling rigs and well service rigs. In performing the impairment evaluation, we13% discount rate to estimate the future undiscounted net cash flows relating to long-lived assets and intangible assets grouped at the lowest level that cash flows can be identified. Our long-lived assets and intangible assets for our Production Services Division are grouped one level below the operating segment in the three reporting units which are well services, wireline services and fishing and rental services. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the long-lived assets and intangible assets in each reporting unit, then we would recognize an impairment charge. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets.the coiled tubing services reporting unit. A decrease in this assumption of 5% would have resulted in a decrease to our goodwill impairment charge of approximately $3.5 million. An increase of 1% in either the utilization or pricing assumptions would have resulted in a decrease to our goodwill impairment charge of approximately $2 million or $3 million, respectively. Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating fair values of reporting units and performing the goodwill impairment evaluation for long-lived assets and intangible assetstest are inherently uncertain and require management judgment.We performed an impairment analysis of our long-lived assets and intangible assets at December 31, 2008, due to significant adverse changes in the economic and business climate that resulted in decreases in estimated revenues, margins and cash flows. Essentially all our intangible assets were recorded in connection with the acquisitions of the production services businesses from WEDGE, Competition, Pettus and Paltec when revenues, margins and cash flows were at historically high levels in early 2008. We determined that the sum of the estimated future undiscounted net cash flows was less than the carrying amount of the long-lived assets and intangible assets in each reporting unit at December 31, 2008. Our impairment analysis resulted in a reduction to our intangible asset carrying value of customers relationships and a non-cash impairment charge of $52.8 million recorded to our operating results for the year ended December 31, 2008.
The cost of our customer relationships is amortized using the straight-line method over their respective estimated economic useful lives which range from seven to nine years. Amortization expense for our non-compete agreements are calculated using the straight-line method over the period of the agreements which range from one to seven years. Amortization expense was $4.6 million, $4.7 million and $8.4 million for the years ended December 31, 2010, 2009 and 2008, respectively. Amortization expense is estimated to be approximately $4.1 million for the year ending December 31, 2011, and $4.0 million for each of the years ending December 31, 2012, 2013, 2014 and 2015. These future amortization amounts are estimates and reflect the
impact of the $52.8 million impairment charge to intangible assets recorded in the year ended December 31, 2008. Actual amortization amounts may be different due to future acquisitions, impairments, changes in amortization periods, or other factors.
Other long-term assets consist of our investment in ARPSs, restricted cash held in an escrow account, cash deposits related to the deductibles on our workers’ compensation insurance policies, the long-term portion of deferred mobilization costs, and loan fees,debt issuance costs, net of amortization. Loan feesamortization, and noncurrent prepaid taxes in Colombia which are describedcreditable against future income taxes.
Other Current Liabilities
Our other accrued expenses include accruals for items such as property tax, sales tax, professional and other fees. We routinely expense these items in
more detail in Note 3,Long-term Debt.the normal course of business over the periods these expenses benefit. Our other accrued expenses also consist of the current portion of the Colombian net equity tax.
Other Long-Term Liabilities
Our other long-term liabilities consist of the noncurrent portion of deferred mobilization revenues, liabilities associated with our long-term compensation plans, the noncurrent portion of the Colombia net equity tax and other deferred liabilities.
Treasury stock purchases are accounted for under the cost method whereby the cost of the acquired common stock is recorded as treasury stock. Gains and losses on the subsequent reissuance of treasury stock shares are credited or charged to additional paid in capital using the average cost method.
Stock-based Compensation
Income TaxesPursuant toWe recognize compensation cost for stock option, restricted stock and restricted stock unit awards based on the fair value estimated in accordance with ASC Topic 740,718, Compensation—Stock Compensation. For our awards with graded vesting, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multiple awards.
We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the market price of our common stock on the exercise date over the exercise price of the stock options. We report all excess tax benefits resulting from the exercise of stock options as financing cash flows in our consolidated statement of cash flows.
Income Taxes (“ASC Topic 740”), we
We follow the asset and liability method of accounting for income taxes, under which we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. We measure our deferred tax assets and liabilities by using the enacted tax rates we expect to apply to taxable income in the years in which we expect to recover or settle those temporary differences. Under ASC Topic 740, we reflect in income theThe effect of a change in tax rates on deferred tax assets and liabilities is reflected in income in the period during which the change occurs. A recent change in Colombia tax rates is described in more detail in Note 6, Comprehensive Income (Loss)Taxes
Comprehensive income (loss) is comprised of net loss and other comprehensive loss. During the years ended December 31, 2009 and 2008, $2.7 million of the difference between the par value and fair value of the ARPSs was considered temporary and was recorded as unrealized losses, net of taxes of $1.0 million, in accumulated other comprehensive income (loss). For the year ended December 31, 2010, we recognized a $3.3 million other-than-temporary impairment of the ARPSs to earnings. The following table sets forth the components of comprehensive loss (amounts in thousands):
| | | | | | | | | | | | |
| | | Years ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | |
Net loss | | $ | (33,261 | ) | | $ | (23,215 | ) | | $ | (62,745 | ) |
Other comprehensive loss: unrealized losses on securities | | | — | | | | (448 | ) | | | (1,245 | ) |
Impact of impairment of investments charge | | | 1,693 | | | | — | | | | — | |
| | | | | | | | | | | | |
Comprehensive loss | | $ | (31,568 | ) | | $ | (23,663 | ) | | $ | (63,990 | ) |
| | | | | | | | | | | | |
Earnings Per Common Share
We compute and present earnings per common share in accordance with ASC Topic 260,Earnings per Share(“ASC Topic 260”). This standard requires dual presentation of basic and diluted earnings per share on the face of our statement of operations.
Stock-based Compensation
Prior to 2010, we granted stock-based compensation in the form of stock option awards and restricted stock awards with vesting based solely on time of service conditions. In 2010, we continued to grant stock option awards with vesting based on time of service conditions and we began granting restricted stock unit awards with vesting based on time of service conditions, and in certain cases, performance conditions. We recognize compensation cost for stock option, restricted stock and restricted stock unit awards based on the grant-date fair value estimated in accordance with ASC Topic 718,Compensation—Stock Compensation(“ASC Topic 718”) and utilizing the graded vesting method.
We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the market price of our common stock on the exercise date over the exercise price of the stock options. In accordance with ASC Topic 718, we reported all excess tax benefits resulting from the exercise of stock options as financing cash flows in our consolidated statement of cash flows.
Related-Party Transactions
Our Chief Executive Officer and President of Drilling Services Division occasionally acquire at fair value a 1% to 5% minority working interest in oil and natural gas wells that we drill for one of our customers. These individuals did not own a working interest in any wells that we drilled for this customer during the years ended December 31, 2010 or 2009. Our President of Drilling Services Division acquired a minority working interest in two wells that we drilled for this customer during the year ended December 31, 2008. We recognized drilling services revenues of $2.0 million on these wells during the year ended December 31, 2008.
Certain amounts in the financial statements for the prior years have been reclassified to conform to the current year’s presentation.
2. Acquisitions
On March 1, 2008,December 31, 2011, we acquired the production services business from WEDGEGo-Coil, L.L.C., a Louisiana limited liability company (“Go-Coil”) which provided well services, wireline services and fishing and rentalcoiled tubing services with a fleet of 62 well service rigs, 45 wirelineseven onshore units and approximately $13 million of fishing and rental equipmentthree offshore units through its facilities in Louisiana, Texas, Kansas, North Dakota, Colorado, UtahOklahoma and Oklahoma.Pennsylvania. The aggregate purchase price for the acquisition was approximately $314.7$110.4 million, which consisted of assets acquired of $340.8$114.9 million and liabilities assumed of $26.1 million. The aggregate purchase price includes $3.4$4.5 million of costs incurred to acquire the production services business from WEDGE.. We financedfunded the acquisition with approximately $3.2 million of cash on hand and $311.5 millionthat was primarily generated from the proceeds of debt incurred under our senior secured revolving credit facilitythe Senior Notes issued in November 2011, as described in Note 3,Long-term Debt.
The following table summarizes the allocation of the purchase price
and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed as of the date of acquisition (amounts in thousands):
| | | | |
Cash acquired | | $ | 1,168 | |
Other current assets | | | 22,102 | |
Property and equipment | | | 138,493 | |
Intangibles and other assets | | | 66,118 | |
Goodwill | | | 112,869 | |
| | | | |
Total assets acquired | | $ | 340,750 | |
| | | | |
| |
Current liabilities | | $ | 10,655 | |
Long-term debt | | | 1,462 | |
Other long term liabilities | | | 13,949 | |
| | | | |
Total liabilities assumed | | $ | 26,066 | |
| | | | |
Net assets acquired | | $ | 314,684 | |
| | | | |
|
| | | |
| Cash acquired | $ | 313 |
|
| Other current assets | 9,068 |
|
| Property and equipment | 30,103 |
|
| Intangibles and other assets | 33,695 |
|
| Goodwill | 41,683 |
|
| Total assets acquired | $ | 114,862 |
|
| Current liabilities | 4,337 |
|
| Long-term debt | 131 |
|
| Total liabilities assumed | 4,468 |
|
| Net assets acquired | $ | 110,394 |
|
The following unaudited pro forma consolidated summary financial information gives effect of the acquisition of the production services business from WEDGEGo-Coil as though it was effective as of the beginning of the year ended December 31, 2008.2011. Pro forma adjustments primarily relate to additional depreciation, amortization, interest and interesttax expenses, as well as the removal of approximately $14.1 million of nonrecurring costs, primarily related to discontinued compensation arrangements and acquisition related costs. The pro forma information reflects our company’s historical data and Go-Coil's historical data from the acquired production services business from WEDGE for the periods indicated. The pro forma data may not be indicative of the results we would have achieved had we completed the acquisition on January 1, 2008,2011, or what we may achieve in the future and should be read in conjunction with the accompanying historical financial statements. | | | | |
| | | Pro Forma
Year Ended
December 31, 2008 | |
| | |
| | |
| | | (in thousands) | |
Total revenues | | $ | 634,535 | |
Net (loss) earnings | | $ | (62,514 | ) |
(Loss) earnings per common share | | | | |
Basic | | $ | (1.26 | ) |
Diluted | | $ | (1.26 | ) |
On March 1, 2008, immediately following the
|
| | | |
| | Pro Forma |
| | For the year ended December 31, 2011 |
| | (in thousands) |
| Total revenues | $ | 762,978 |
|
| Net earnings | $ | 8,412 |
|
| Earnings per common share: | |
| Basic | $ | 0.15 |
|
| Diluted | $ | 0.14 |
|
The acquisition of the productioncoiled tubing services business from WEDGE, we acquired the production services business from Competition which provided wireline services with a fleet of 6 wireline units through its facilities in Montana. The aggregate purchase price for the Competition acquisitionGo-Coil was approximately $30.0 million, which consisted of assets acquired of $30.1 million and liabilities assumed of $0.1 million. The aggregate purchase price includes $0.4 million of costs incurred to acquire the production services business from Competition. We financed the acquisition with $26.7 million cash on hand and a note payable due to the prior owner for $3.3 million. Goodwill of $5.3 million and intangible assets and other assets of $18.0 million were recorded in connection with the acquisition.On August 29, 2008, we acquired the wireline services business from Paltec, Inc. (“Paltec”). The aggregate purchase price was $7.8 million which we financed with $6.5 million in cash and a sellers note of $1.3 million. Intangible and other assets of $4.3 million and goodwill of $0.1 million were recorded in connection with the acquisition.
On October 1, 2008, we acquired the well services business from Pettus Well Service (“Pettus”). The aggregated purchase price was $3.0 million which we financed with $2.8 million in cash and a sellers note of $0.2 million. Intangible and other assets of $1.2 million and goodwill of $0.1 million were recorded in connection with the acquisition.
The acquisitions of the production services businesses from WEDGE, Competition, Paltec and Pettus were accounted for as acquisitionsan acquisition of businesses.a business in accordance with ASC Topic 805,
Business Combinations. The purchase price allocationsallocation for these production services businesses werethe Go-Coil acquisition was finalized as of December 31, 2008.June 30, 2012. Goodwill was recognized as part of the WEDGE, Competition, Paltec and Pettus acquisitionsGo-Coil acquisition, since the purchase price exceeded the estimated fair value of the assets acquired and liabilities assumed. We believedbelieve that the goodwill was relatedrelates to the acquired workforces,workforce, future synergies between our existing Drilling Services Division and our new Production Services Divisionservice offerings and the ability to expand our service offerings. These Prior to the Go-Coil acquisition, we completed four separate acquisitions occurred between March 1, 2008 and October 1, 2008, whenin 2011 of other production service revenues, margins and cash flows and our market capitalization were at historically high levels. As described in Note 1, our goodwill impairment analysis performed at December 31, 2008 led us to conclude that there would be no remaining implied value attributable to our goodwill and accordingly, we recorded a non-cash charge of $118.6 millionservices businesses for a full impairmenttotal of goodwill relating to these acquisitions. We also performed an impairment analysis which resulted$6.5 million in an impairment charge of $52.8 million and reduction in the intangible asset carrying value of customer relationships relating to these acquisitions. These impairment charges were primarily related to significant adverse changes in the economic and business climate that occurred during the fourth quarter of the year ended December 31, 2008.On April 1, 2010, we acquired Tiger Wireline Services, Inc. (“Tiger”), which provided wireline services with two wireline units through its facilities in Kansas. The aggregate purchase price was approximately $1.9 million, which we financed with $1.3 million in cash and a seller’s note of $0.6 million.cash. The identifiable assets recorded in connection with this acquisition includethese acquisitions included fixed assets of $0.8$5.2 million, representing six wireline units and two well servicing rigs, and intangible assets of $1.1$1.3 million representing customerclient relationships and a non-competition agreement.agreements. We did not recognize any goodwill in conjunction with the acquisitionthese acquisitions and no contingent assets or liabilities were assumed. Our acquisition of Tiger hasThese four acquisitions have been accounted for as an acquisitionacquisitions of a businessbusinesses in accordance with ASC Topic 805,Business Combinations.
Long-term
3. Property and Equipment
As of December 31, 2013, the estimated useful lives and costs of our asset classes are as follows:
|
| | | | | |
| | Lives | | Cost |
| | | | (amounts in thousands) |
| Drilling rigs and equipment | 3 - 25 | | $ | 1,223,621 |
|
| Well servicing rigs and equipment | 3 - 20 | | 205,409 |
|
| Wireline units and equipment | 2 - 10 | | 128,800 |
|
| Coiled tubing units and equipment | 1 - 7 | | 47,761 |
|
| Fishing and rental tools and equipment | 3 - 15 | | 17,264 |
|
| Vehicles | 3 - 20 | | 65,796 |
|
| Office equipment | 3 - 10 | | 9,274 |
|
| Buildings and improvements | 3 - 40 | | 23,931 |
|
| Land | — | | 2,268 |
|
| | | | $ | 1,724,124 |
|
As of December 31, 2013 and 2012, we had incurred $19.4 million and $134.9 million, respectively, in construction costs for ongoing projects, primarily for our new-build drilling rigs and additions to our production services fleets. During the years ended December 31, 2013, 2012 and 2011, we capitalized $0.9 million, $10.2 million and $2.3 million, respectively, of interest costs incurred primarily during the construction periods of new-build drilling rigs and other drilling equipment.
We recorded gains on disposition of our property and equipment of $1.4 million, gains of $1.2 million and losses of $0.2 million during the years ended December 31, 2013, 2012 and 2011, respectively, in our drilling and production services costs and expenses. During the second quarter of 2013, we sold two mechanical drilling rigs that were previously idle in our East Texas division, for which we recognized an associated gain of approximately $0.8 million. Additionally, we disposed of a total of four wireline units during 2013, as well as other wireline equipment.
We recorded impairment charges on our property and equipment of $9.2 million,$1.1 millionand$0.5 millionfor the year ended December 31, 2013, 2012 and 2011, respectively. During the third quarter of 2013, we decided to place eight of our mechanical drilling rigs as held for sale, and we recognized an impairment loss of $9.2 million in order to reduce the carrying value of these assets to their estimated fair value, based on their sales price. The sales of all eight drilling rigs were completed in late October 2013 and we did not incur any additional gain or loss upon the sale of these rigs. We also recorded an impairment of $0.3 million during the third quarter of 2013 in association with our decision to sell certain production services equipment. In March 2012, we retired two mechanical drilling rigs, with most of their components to be used as spare parts, as well as two wireline units and other wireline equipment, and recognized an associated impairment charge of $1.1 million. In September 2011, we decided to place six mechanical drilling rigs as held for sale and to retire another drilling rig from our fleet, with most of its components to be used as spare parts. Sales of all six mechanical drilling rigs were completed by mid November 2011 and we recognized an impairment charge of $0.5 million in September 2011 in association with our decision to dispose of these seven drilling rigs.
We evaluate for potential impairment of long-lived tangible and intangible assets subject to amortization when indicators of impairment are present. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts for drilling rigs and well servicing rigs. In performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of long-lived tangible and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for the individual reporting units (well servicing, wireline, coiled tubing and fishing and rental services).For
our Drilling Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual drilling rig assets.If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the asset group, then we would determine the fair value of the asset group. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management judgment.
In September 2013, we evaluated the drilling rigs in our fleet and decided to place eight of our mechanical drilling rigs as held for sale and recognized an impairment charge to reduce the carrying value of these assets to their estimated fair value, which was based on their sales price. The decision to sell these drilling rigs was primarily due to a decrease in demand for non-top drive mechanical rigs that drill vertical oil and gas wells. Our remaining drilling rig fleet includes mechanical rigs that are currently working, but which may have reduced utilization if demand for vertical drilling continues to soften. We performed an impairment evaluation on the remaining drilling rigs in our fleet which are similar to those that we decided to sell. In order to estimate our future undiscounted cash flows from the use and eventual disposition of these assets, we incorporated probabilities of selling these rigs in the near term, versus working them through the end of their remaining useful lives. Our analysis led us to conclude that no impairment presently exists for the remaining similar drilling rigs. If the demand for vertical drilling continues to soften and these remaining mechanical rigs become idle for an extended amount of time, then the probability of a near term sale may increase, which would likely result in an impairment charge, based on the current market value of these drilling rigs. Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions.
Due to several significant adverse factors affecting our coiled tubing services reporting unit, including increased competition in certain coiled tubing markets, turnover of key personnel and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of our long-lived tangible and intangible assets as of June 30, 2013. We determined that the sum of the estimated future undiscounted net cash flows for our coiled tubing services reporting unit was less than the carrying amount, and recorded impairment charges to reduce the carrying value of our goodwill to zero and to reduce the carrying value of our intangibles to estimated fair value as of June 30, 2013. However, our impairment analysis did not result in any impairment charges to our coiled tubing property and equipment.
4. Debt
Our debt consists of the following (amounts in thousands):
| | | | | | | | |
| | | December 31, 2010 | | | December 31, 2009 | |
| | |
Senior secured revolving credit facility | | $ | 37,750 | | | $ | 257,500 | |
Senior notes | | | 240,080 | | | | — | |
Subordinated notes payable | | | 3,045 | | | | 4,387 | |
Other | | | 63 | | | | 227 | |
| | | | | | | | |
| | | 280,938 | | | | 262,114 | |
Less current portion | | | (1,408 | ) | | | (4,041 | ) |
| | | | | | | | |
| | $ | 279,530 | | | $ | 258,073 | |
| | | | | | | | |
|
| | | | | | | |
| | December 31, 2013 | | December 31, 2012 |
| Senior secured revolving credit facility | $ | 80,000 |
| | $ | 100,000 |
|
| Senior notes | 419,586 |
| | 418,617 |
|
| Other | 2,927 |
| | 980 |
|
| | 502,513 |
| | 519,597 |
|
| Less current portion | (2,847 | ) | | (872 | ) |
| | $ | 499,666 |
| | $ | 518,725 |
|
Senior Secured Revolving Credit Facility
We have a credit agreement, as amended on June 30, 2011, with Wells Fargo Bank, N.A. and a syndicate of lenders which provides for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-line loans, of up to an aggregate principal amount of $225$250 million, all of which matures on August 31, 2012June 30, 2016 (the “Revolving Credit Facility”). The Revolving Credit Facility contains customary mandatory prepayments in respectfrom the proceeds of certain asset dispositions or debt incurrence and equity issuances, which are applied to reduce outstanding revolving and swing-lineswing-line loans and letter of credit exposure, but in no event will reduce the borrowing availability under the Revolving Credit Facility to less than $225 million.
$250 million.
Borrowings under the Revolving Credit Facility bear interest, at our option, at the LIBOR rate or at the bank prime rate, plus an applicable per annum margin that ranges from 3.50%2.50% to 6.00%3.25% and 2.50%1.50% to 5.00%2.25%, respectively. The LIBOR margin and bank prime rate margin currently in effect at February 4, 2011 are 4.50%2.75% and 3.50%1.75%, respectively. The Revolving Credit Facility requires a commitment fee due quarterly based on the average daily unused amount of the commitments of the lenders, a fronting fee due for each letter of credit issued, and a quarterly letter of credit fee due based on the average undrawn amount of letters of credit outstanding during such period.
Our obligations under the Revolving Credit Facility are secured by substantially all of our domestic assets (including equity interests in Pioneer Global Holdings, Inc. and 65% of the outstanding equity interests of any first-tier foreign subsidiaries owned by Pioneer Global Holdings, Inc., but excluding any equity interest in, and any assets of, Pioneer Services Holdings, LLC) and are guaranteed by certain of our domestic subsidiaries, including Pioneer Global Holdings, Inc. Effective October 1, 2012, Pioneer Coiled Tubing Services, LLC (formerly Go-Coil, L.L.C.) was added as a subsidiary guarantor under the Revolving Credit Facility. Borrowings under the Revolving Credit Facility are available for acquisitions, working capital and other general corporate purposes.In March 2010, we made a payment
As of $234.8 million to reduce the outstanding debt balance under the Revolving Credit Facility, using the net proceeds from the issuance of our Senior Notes which is described below. We may choose to make additional principal payments to reduce the outstanding debt balance prior to maturity on August 31, 2012 when cash and working capital is sufficient. We made a $12.8 million principal payment after December 31, 2010, which resulted in a $25.02013, we had $80.0 million outstanding balance under our Revolving Credit Facility and $9.2$14.0 million in committed letters of credit, at February 4, 2011. Therefore, ourwhich resulted in borrowing availability of $156.0 million under our Revolving Credit Facility was $190.8 million as of February 4, 2011.Facility. There are no limitations on our ability to access this borrowing capacity other than maintaining compliance with the covenants under the Revolving Credit Facility. At December 31, 2010,2013, we were in compliance with our financial covenants.covenants under the Revolving Credit Facility. Our total consolidated leverage ratio was 2.72.0 to 1.0, our senior consolidated leverage ratio was 0.4 to 1.0, and our interest coverage ratio was 4.25.3 to 1.0. The financial covenants contained in our Revolving Credit Facility include the following: A maximum total consolidated leverage ratio that cannot exceed:
5.00exceed 4.00 to 1.00 as of the end of any fiscal quarter ending December 31, 2010 through June 30, 2011;
1.00;4.75 to 1.00 as of the end of the fiscal quarter ending September 30, 2011;
4.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2011;
4.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2012; and
4.00 to 1.00 as of the end of any fiscal quarter ending June 30, 2012 and thereafter.
A maximum senior consolidated leverage ratio, which excludes unsecured and subordinated debt, that cannot exceed:
4.50exceed 2.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2010;
1.00;
4.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2011;
4.00 to 1.00 as of the end of the fiscal quarter ending June 30, 2011;
3.75 to 1.00 as of the end of the fiscal quarter ending September 30, 2011;
3.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2011;
3.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2012; and
3.00 to 1.00 as of the end of any fiscal quarter ended June 30, 2012 and thereafter.
A minimum interest coverage ratio that cannot be less than:
2.00than 2.50 to 1.00 as of the end of any fiscal quarter ending December 31, 2010 through December 31, 2011;1.00; and
3.00 to 1.00 as of the end of any fiscal quarter ending March 31, 2012 and thereafter.
If our senior consolidated leverage ratio is greater than 2.252.00 to 1.00 at the end of any fiscal quarter, aour minimum asset coverage ratio that cannot be less than 1.00 to 1.00 for any fiscal quarter ending on or before December 31, 2011, and 1.10 to 1.00 for any fiscal quarter ending March 31, 2012 and thereafter (as provided in the1.00.
The Revolving Credit Facility). If our senior consolidated leverage ratio is greater than 2.25 to 1.00 and our asset coverage ratio is less than 1.00 to 1.00, then borrowings outstandingFacility does not restrict capital expenditures as long as (a) no event of default exists under the Revolving Credit Facility will be limited to the sum of 80% of eligible accounts receivable, 80% of the orderly liquidation value of eligible equipment and 40% of the net book value of certain other fixed assets.
The Revolving Credit Facility restrictsor would result from such capital expenditures, unless (a)(b) after giving effect to such capital expenditure, no event of default would exist under the Revolving Credit Facility andexpenditures there is availability under the Revolving Credit Facility would be equal to or greater than $25
$25 million and (b) if(c) the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter wasis less than 2.00 to 1.00. If the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter is equal to or greater than 2.502.00 to 1.00, such capital expenditure would not cause the sum of allthen capital expenditures are limited to exceed:
$65100 million for the fiscal year 2010; and
$80 million for each fiscal year thereafter.
year. The capital expenditure thresholds for each period noted abovethreshold may be increased by:
the first $25 million of any aggregate equity issuance proceeds received during such period and 25% of any equity issuance proceeds received in excess of $25 million during such period; and
25% of any debt incurrence proceeds received during such period.
In addition,by any unused portion of the capital expenditure threshold up to $30 million can be carried over from the immediate preceding fiscal year.
year up to $30 million.
At December 31, 2010,2013, our senior consolidated leverage ratio was not greater than 2.502.00 to 1.00 and therefore, we were not subject to the capital expenditure threshold restrictions listed above. The Revolving Credit Facility has additional restrictive covenants that, among other things, limit the incurrence of additional debt, investments, liens, dividends, acquisitions, redemptions of capital stock, prepayments of indebtedness, asset dispositions, mergers and consolidations, transactions with affiliates, hedging contracts, sale leasebacks and other matters customarily restricted in such agreements. In addition, the Revolving Credit Facility contains customary events of default, including without limitation, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults to certain other material indebtedness in excess of specified amounts, certain events of bankruptcy and insolvency, judgment defaults in excess of specified amounts, failure of any guaranty or security document supporting the credit agreement and change of control.
On March 11, 2010, we issued $250$250 million of unregistered Senior Notessenior notes with a coupon interest rate of 9.875% that are due in 2018 (the “Senior“2010 Senior Notes”). The 2010 Senior Notes were sold with an original issue discount of $10.6$10.6 million that was based on 95.75% of their face value, which will result in an effective yield to maturity of approximately 10.677%. On March 11, 2010, we received $234.8$234.8 million of net proceeds from the issuance of the 2010 Senior Notes after deductions were made for the $10.6$10.6 million of original issue discount and $4.6$4.6 million for underwriters’ fees and other debt offering costs. The net proceeds were used to repay a portion of the borrowings outstanding under our Revolving Credit Facility. On November 21, 2011, we issued $175 million of unregistered Senior Notes (the “2011 Senior Notes”). The 2011 Senior Notes have the same terms and conditions as the 2010 Senior Notes. The 2011 Senior Notes were sold with an original issue premium of $1.8 million that was based on 101% of their face value, which will result in an effective yield to maturity of approximately 9.66%. On November 21, 2011, we received $172.7 million of net proceeds from the issuance of the 2011 Senior Notes, including the original issue premium, and after $4.1 million of deductions were made for underwriters' fees and other debt offering costs. A portion of the net proceeds were used to fund the acquisition of Go-Coil in December 2011.
In accordance with a registration rights agreement with the holders of
both our
2010 Senior Notes and 2011 Senior Notes, we filed
an exchange offer registration
statementstatements on Form S-4 with the Securities and Exchange Commission that became effective on September 2,
2010. This2010 and July 13, 2012, respectively. These exchange offer registration
statementstatements enabled the holders of
both our
2010 Senior Notes and 2011 Senior Notes to exchange their
Senior Notessenior notes for publicly registered notes with substantially identical terms. References to the
“Senior“2010 Senior Notes” and “2011 Senior Notes” herein include the
Senior Notessenior notes issued in the exchange
offer.offers.
The 2010 and 2011 Senior Notes (the “Senior Notes”) are reflected on our condensed consolidated balance sheet at December 31, 20102013 with a total carrying value of $240.1$419.6 million, which represents the $250$425.0 million total face value net of the $9.9$6.7 million unamortized portion of original issue discount.discount and $1.3 million unamortized portion of original issue premium. The original issue discount isand premium are being amortized over the term of the Senior Notes based on the effective interest method.
The Senior Notes will mature on March 15, 2018 with interest due semi-annually in arrears on March 15 and September 15 of each year, commencing on September 15, 2010.year. We have the option to redeem the Senior Notes, in whole or in part, at any time on or after March 15, 2014 in each case at the redemption price specified in the Indenture dated March 11, 2010 (the “Indenture”) together with any accrued and unpaid interest to the date of redemption. Prior to March 15, 2014, we may also redeem the Senior Notes, in whole or in part, at a “make-whole” redemption price specified in the Indenture, together with any accrued and unpaid interest to the date of redemption. In addition, prior to March 15, 2013, we may, on one or more occasions, redeem up to 35% of the aggregate principal amount of the Senior Notes at a redemption price of 109.875% of the principal amount, plus any accrued and unpaid interest to the redemption date, with the net proceeds of certain equity offerings, if at least 65% of the aggregate principal amount of the Senior Notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing of the equity offering. Upon the occurrence of a change of control, holders of the Senior Notes will have the right to require us to purchase all or a portion of the Senior Notes at a price equal to 101% of the principal amount of each Senior Note, together with any accrued and unpaid interest to the date of purchase. Under certain circumstances in connection with asset dispositions, we will be required to use the excess proceeds of asset dispositions to make an offer to purchase the Senior Notes at a price equal to 100% of the principal amount of each Senior Note, together with any accrued and unpaid interest to the date of purchase.
The Indenture contains certain restrictions
generally on our and certain of our subsidiaries’ ability to:
repurchase stock or redeem subordinated debt or make other restricted payments;
incur, assume or guarantee additional indebtedness or issue disqualified stock;
create liens on our assets;
enter into sale and leaseback transactions;
pay dividends, engage in loans, or transfer other assets from certain of our subsidiaries;
consolidate with or merge with or into, or sell all or substantially all of our properties to another person;
enter into transactions with affiliates; and
enter into new lines of business.
These covenants are subject to important exceptions and qualifications. We were in compliance with these covenants as of December 31, 2010.2013. The Senior Notes are not subject to any sinking fund requirements. The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by certain of our existing domestic subsidiaries and by certain of our future domestic subsidiaries (seesubsidiaries. Effective October 1, 2012, Pioneer Coiled Tubing Services, LLC (formerly Go-Coil, L.L.C.) was added as a subsidiary guarantor under the Indenture. (See Note 13,14, Guarantor/Non-Guarantor Condensed Consolidated Financial Statements.).Other Debt
Subordinated Notes Payable and OtherIn addition to amounts outstanding under our Revolving Credit Facility and Senior Notes, long-term debt includes subordinated notes payable to certain employees that are former shareholders of the production services businesses that were acquired by WEDGE prior to our acquisition of WEDGE on March 1, 2008, a subordinated note payable to an employee that is a former shareholder of Competition and three subordinated notes payable to
certain employees that are former shareholders of Paltec, Pettus and Tiger. These subordinated notes payable have interest rates ranging from 5.4% to 14%, require quarterly or annual payments of principal and interest and have final maturity dates ranging from January 2011 to April 2013. The aggregate outstanding balance of these subordinated notes payable was $3.0 million as of December 31, 2010.
OtherOur other debt represents a short-term financing arrangementof insurance premiums with monthly payments due through August 2014 and a capital lease obligation for computer softwareequipment with an outstanding balance of $0.1 million at December 31, 2010.
monthly payments due through November 2016.
Costs incurred in connection with ourthe Revolving Credit Facility were capitalized and are being amortized using the straight-line method over the term of the Revolving Credit Facility which matures in August 2012.June 2016. Costs incurred in connection with the issuance of our Senior Notes were capitalized and are being amortized using the straight-line method (which approximates the use of the interest method) over the term of the Senior Notes which mature in March 2018. 2018.
Capitalized debt costs related to the issuance of our long-term debt were approximately $6.7$7.5 million and $3.8$9.6 million as of December 31, 20102013 and December 31, 2009,2012, respectively. We recognized approximately $1.9$2.1 million $1.5, $2.1 million and $0.6$1.8 million of associated amortization during the years ended December 31, 2010, 20092013, 2012 and 2008,2011, respectively. During 2011, we recognized additional amortization expense for the write-off of $0.6 million of debt issuance costs representing the portion of unamortized debt issuance costs associated with certain syndicate lenders who are no longer participating in the Revolving Credit Facility as amended on June 30, 2011. We lease our corporate office facilities in San Antonio, Texas at a payment escalating from $27,911$40,373 per month in January 20112014 to $29,316$46,920 per month in December 2020 pursuant to a lease extendingwhich extends through December 2013.2020, but which is cancelable as early as December 2016 with applicable penalties. We recognize rent expense on a straight linestraight-line basis for our corporate office lease. In addition, weWe also lease real estate at 3952 other locations, under non-cancelable operating leases with payments ranging from $250 per month to $27,169 per month, pursuant to leases expiring through August 2015. These real estate locationswhich are primarily used primarily for divisionfield offices and storage and maintenance yards. We alsoyards, and we lease vehicles, office and other equipment under non-cancelable operating leases, expiring through November 2013.most of which contain renewal options and some of which contain escalation clauses.
Future lease obligations required under non-cancelable operating leases as of December 31, 20102013 were as follows (amounts in thousands): | | | | |
Years Ended December 31, | | | |
2011 | | $ | 2,408 | |
2012 | | | 1,885 | |
2013 | | | 1,484 | |
2014 | | | 586 | |
2015 | | | 164 | |
Thereafter | | | — | |
| | | | |
| | $ | 6,527 | |
| | | | |
|
| | | |
| Year ended December 31, | |
| 2014 | $ | 5,032 |
|
| 2015 | 2,987 |
|
| 2016 | 2,428 |
|
| 2017 | 2,024 |
|
| 2018 | 1,082 |
|
| Thereafter | 1,366 |
|
| | $ | 14,919 |
|
Rent expense under operating leases for the years ended December 31, 2010, 20092013, 2012 and 20082011 was $2.9$6.0 million $2.1, $5.6 million and $1.4$3.6 million, respectively. The jurisdictional components of lossincome (loss) before income taxes consist of the following (amounts in thousands): | | | | | | | | | | | | |
| | | Years ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
Domestic | | $ | (48,650 | ) | | $ | (46,221 | ) | | $ | (62,388 | ) |
Foreign | | | 1,092 | | | | 6,049 | | | | 5,700 | |
| | | | | | | | | | | | |
Loss before income tax | | $ | (47,558 | ) | | $ | (40,172 | ) | | $ | (56,688 | ) |
| | | | | | | | | | | | |
|
| | | | | | | | | | | |
| | Year ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Domestic | $ | (66,147 | ) | | $ | 42,194 |
| | $ | 23,396 |
|
| Foreign | 10,369 |
| | 4,192 |
| | (2,563 | ) |
| Income (loss) before income tax | $ | (55,778 | ) | | $ | 46,386 |
| | $ | 20,833 |
|
The components of our income tax expense (benefit) consist of the following (amounts in thousands): | | | | | | | | | | | | |
| | | Years ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
Current tax: | | | | | | | | | | | | |
Federal | | $ | (2,547 | ) | | $ | (46,073 | ) | | $ | 3,777 | |
State | | | 32 | | | | (2,969 | ) | | | 1,181 | |
Foreign | | | 931 | | | | 1,087 | | | | 348 | |
| | | | | | | | | | | | |
| | | (1,584 | ) | | | (47,955 | ) | | | 5,306 | |
| | | | | | | | | | | | |
Deferred taxes: | | | | | | | | | | | | |
Federal | | | (13,046 | ) | | | 31,740 | | | | 476 | |
State | | | 1,366 | | | | 3,390 | | | | (211 | ) |
Foreign | | | (1,033 | ) | | | (4,132 | ) | | | 486 | |
| | | | | | | | | | | | |
| | | (12,713 | ) | | | 30,998 | | | | 751 | |
| | | | | | | | | | | | |
Income tax expense (benefit) | | $ | (14,297 | ) | | $ | (16,957 | ) | | $ | 6,057 | |
| | | | | | | | | | | | |
|
| | | | | | | | | | | |
| Year ended December 31, |
| 2013 | | 2012 | | 2011 |
| Current tax: | | | | | |
| Federal | $ | (380 | ) | | $ | 236 |
| | $ | 716 |
|
| State | 879 |
| | 1,214 |
| | 1,090 |
|
| Foreign | 2,302 |
| | 1,479 |
| | 1,301 |
|
| | 2,801 |
| | 2,929 |
| | 3,107 |
|
| Deferred taxes: | | | | | |
| Federal | (21,034 | ) | | 15,013 |
| | 7,199 |
|
| State | (3,520 | ) | | (749 | ) | | 102 |
|
| Foreign | 1,907 |
| | (839 | ) | | (752 | ) |
| | (22,647 | ) | | 13,425 |
| | 6,549 |
|
| Income tax expense (benefit) | $ | (19,846 | ) | | $ | 16,354 |
| | $ | 9,656 |
|
The difference between the income tax expense (benefit) expense and the amount computed by applying the federal statutory income tax rate of 35% to lossincome (loss) before income taxes consistconsists of the following (amounts in thousands): | | | | | | | | | | | | |
| | | Years ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
Expected tax benefit | | $ | (16,645 | ) | | $ | (14,060 | ) | | $ | (19,840 | ) |
State income taxes | | | 909 | | | | 274 | | | | 556 | |
Incentive stock options | | | 266 | | | | 243 | | | | 508 | |
Goodwill impairment | | | — | | | | — | | | | 26,752 | |
Tax benefits in foreign jurisdictions | | | (207 | ) | | | (5,162 | ) | | | (1,377 | ) |
Domestic production activities deduction | | | — | | | | 1,130 | | | | (457 | ) |
Tax-exempt interest income | | | (23 | ) | | | (33 | ) | | | (219 | ) |
Non deductible items for tax purposes | | | 349 | | | | 218 | | | | 247 | |
Valuation allowance | | | 1,248 | | | | — | | | | — | |
Other, net | | | (194 | ) | | | 433 | | | | (113 | ) |
| | | | | | | | | | | | |
Income tax expense (benefit) | | $ | (14,297 | ) | | $ | (16,957 | ) | | $ | 6,057 | |
| | | | | | | | | | | | |
|
| | | | | | | | | | | |
| | Year ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Expected tax expense (benefit) | $ | (19,522 | ) | | $ | 16,235 |
| | $ | 7,291 |
|
| State income taxes | (1,717 | ) | | 302 |
| | 775 |
|
| Incentive stock options | 66 |
| | 43 |
| | 41 |
|
| Net tax benefits and nondeductible expenses in foreign jurisdictions | 525 |
| | (881 | ) | | 1,391 |
|
| Nondeductible expenses for tax purposes | 863 |
| | 770 |
| | 567 |
|
| Valuation allowance | — |
| | (206 | ) | | — |
|
| Other, net | (61 | ) | | 91 |
| | (409 | ) |
| Income tax expense (benefit) | $ | (19,846 | ) | | $ | 16,354 |
| | $ | 9,656 |
|
Income tax expense (benefit) was allocated as follows (amounts in thousands): | | | | | | | | | | | | |
| | | Years ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
Results of operations | | $ | (14,297 | ) | | $ | (16,957 | ) | | $ | 6,057 | |
Stockholders' equity | | | 1,332 | | | | (26 | ) | | | (963 | ) |
| | | | | | | | | | | | |
Income tax expense (benefit) | | $ | (12,965 | ) | | $ | (16,983 | ) | | $ | 5,094 | |
| | | | | | | | | | | | |
|
| | | | | | | | | | | |
| | Year ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Results of operations | $ | (19,846 | ) | | $ | 16,354 |
| | $ | 9,656 |
|
| Stockholders' equity | 321 |
| | 449 |
| | 254 |
|
| Income tax expense (benefit) | $ | (19,525 | ) | | $ | 16,803 |
| | $ | 9,910 |
|
Deferred income taxes arise from temporary differences between the tax
basesbasis of assets and liabilities and their reported amounts in the consolidated financial statements. The components of our deferred income tax assets and liabilities were as follows (amounts in thousands):
| | | | | | | | |
| | | December 31,
2010 | | | December 31,
2009 | |
Deferred tax assets: | | | | | | | | |
Auction rate preferred securities | | $ | 1,248 | | | $ | 983 | |
Intangibles | | | 21,594 | | | | 22,365 | |
Employee benefits and insurance claims accruals | | | 3,634 | | | | 3,338 | |
Accounts receivable reserve | | | 42 | | | | 99 | |
Employee stock based compensation | | | 6,099 | | | | 4,439 | |
Accrued expenses not deductible for tax purposes | | | — | | | | 1,919 | |
Accrued revenue not income for book purposes | | | 3,393 | | | | 1,649 | |
Federal and state net operating loss and AMT credit carryforward | | | 21,568 | | | | 4,718 | |
Foreign net operating loss carryforward | | | 5,713 | | | | 4,071 | |
| | | | | | | | |
| | | 63,291 | | | | 43,581 | |
Valuation allowance | | | (1,248 | ) | | | — | |
| | | | | | | | |
Total deferred tax assets | | | 62,043 | | | | 43,581 | |
| | | | | | | | |
Deferred tax liabilities: | | | | | | | | |
Accrued expenses not deductible for tax purposes | | | 105 | | | | — | |
Property and equipment | | | 132,231 | | | | 125,855 | |
| | | | | | | | |
Total deferred tax liabilities | | | 132,336 | | | | 125,855 | |
| | | | | | | | |
Net deferred tax liabilities | | $ | 70,293 | | | $ | 82,274 | |
| | | | | | | | |
|
| | | | | | | |
| | Year ended December 31, |
| | 2013 | | 2012 |
| Deferred tax assets: | | | |
| Capital loss carryforward | $ | 1,008 |
| | $ | 1,008 |
|
| Intangibles | 36,442 |
| | 19,918 |
|
| Employee benefits and insurance claims accruals | 9,332 |
| | 8,273 |
|
| Accounts receivable reserve | 501 |
| | 370 |
|
| Employee stock-based compensation | 8,905 |
| | 8,225 |
|
| Accrued expenses not deductible for tax purposes | 749 |
| | 1,066 |
|
| Accrued revenue not income for book purposes | 942 |
| | 1,399 |
|
| Federal and state net operating loss and AMT credit carryforward | 94,605 |
| | 69,160 |
|
| Foreign net operating loss carryforward | 3,411 |
| | 5,361 |
|
| | 155,895 |
| | 114,780 |
|
| Valuation allowance | (1,008 | ) | | (1,008 | ) |
| Total deferred tax assets | 154,887 |
| | 113,772 |
|
| Deferred tax liabilities: | | | |
| Property and equipment | 225,275 |
| | 206,033 |
|
| Total deferred tax liabilities | 225,275 |
| | 206,033 |
|
| Net deferred tax liabilities | $ | 70,388 |
| | $ | 92,261 |
|
In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Based on the expectation of future taxable income and that the deductible temporary differences will offset existing taxable temporary differences, we believe it is more likely than not that we will realize the benefits of these deductible temporary differences, with the exception of the valuation allowance recorded to fully offset our deferred tax asset
for a capital loss carryforward related to the unrealized loss on the impairment of our ARPS securities.
As of December 31, 2010,2013, we had a $1.2$1.0 million deferred tax asset related to the $3.3 million impairmentsale of our ARPSs which will represent a capital loss for tax treatment purposes. We can recognize a tax benefit associated with this impairmentloss to the extent of capital gains we expect to earn in future periods. We recorded a valuation allowance to fully offset our deferred tax asset relating to this capital loss since we believe capital gains are not likely in future periods. As of December 31, 2010,2013, we had $21.6$94.6 million and $5.7$3.4 million of deferred tax assets related to domestic and foreign net operating losses, respectively, that are available to reduce future taxable income. In assessing the realizability of our deferred tax assets, we only recognize a tax benefit to the extent of taxable income that weexpect to earn in the jurisdiction in future periods. We estimate that our operations will result in taxable income in excess of our net operating losses and we expect to apply the net operating losses against taxable income that we have estimated in future periods. The domestic net operating losses can be used to offset future domestic taxable income through 2020,
2033, while the majority of the foreign net operating losses can be carried forward indefinitely. Deferred income taxes have not been provided on the future tax consequences attributable to difference between the financial statements carrying amounts of existing assets and liabilities and the respective tax bases of our foreign subsidiary based on the determination that such differences are essentially permanent in duration in that the earnings of the subsidiary is expected to be indefinitely reinvested in foreign operations. As of December 31, 2010,2013, the cumulative undistributed earnings/loss of the subsidiary was approximately a $2.3$18.0 million loss. If those earnings were not considered indefinitely reinvested, deferred income taxes would have been recorded after consideration of foreign tax credits. It is not practicable to estimate the amount of additional tax that might be payable on those earnings, if distributed. On December 26, 2012, Colombia enacted a tax reform bill that, among other things, decreased the corporate tax rate from 33% to 25%, but also added a new 9% tax for equality, which results in a combined tax rate of 34%. Net operating losses cannot be utilized against the new 9% tax for equality, and therefore the associated deferred tax asset must now be based on the lower 25% corporate tax rate only. Other deferred tax assets and liabilities must now be based on the higher combined tax rate of 34%. Included in our 2012 deferred foreign tax expense (benefit) is a $1.7 million expense to adjust our Colombian net deferred tax assets and liabilities for the change in rates.
We have no unrecognized tax benefits relating to ASC Topic 740 and no unrecognized tax benefit activity during the year ended December 31, 2010.2013
. We adopted a policy to record interest and penalty expense related to income taxes as interest and other expense, respectively. At December 31, 2010,2013, no interest or penalties have been or are required to be accrued. Our open tax years for our federal income tax returns in the United States are for the years ended March 31, 2007, December 31, 2007, December 31, 2008 and December 31, 2009.2010 to 2012. Our open tax years for our income tax returns in Colombia are for the years ended December 31, 2008 and December 31, 2009.to 2012. 6. | |
| 7. | Fair Value of Financial Instruments |
Our
ASC Topic 820, Fair Value Measurements and Disclosures, defines fair value and provides a hierarchal framework associated with the level of subjectivity used in measuring assets and liabilities at fair value.
At December 31, 2013 and December 31, 2012, our financial instruments consist primarily of cash, trade and other receivables, trade payables, and long-term debt, and our investments in ARPS.debt. The carrying value of cash, trade and other receivables and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments.Our ARPSs are reported at amounts that reflect our estimate of fair value. To estimate the fair values of our ARPSs as of December 31, 2010, we used inputs defined by ASC Topic 820 as level 1 inputs which are quoted market prices in active markets for identical securities. Subsequent to year end, we entered into a settlement agreement with a financial institution to sell the ARPSs for $12.6 million, plus accrued interest, and liquidated the ARPS on January 25, 2011. Therefore, the $12.6 million sales price under the settlement agreement represents the fair value of the ARPSs at December 31, 2010. The $3.3 million difference between the ARPSs’ par value of $15.9 million and the fair value of $12.6 million represents an other-than-temporary impairment which is reflected as an impairment of investments in our consolidated statement of operations for the year ended December 31, 2010.
To estimate the fair values of our ARPSs as of December 31, 2009, we used inputs defined by ASC Topic 820 as level 3 inputs which are unobservable for the asset or liability and are developed based on the best information available in the circumstances. We estimated the fair value of our ARPSs based on discounted cash flow models and secondary market comparisons of similar securities. Based on this methodology, the estimated fair value of our ARPSs was $13.2 million at December 31, 2009, as compared to the par value of $15.9 million at both December 31, 2009. The difference between the ARPSs’ fair value and par value was due to the lack of liquidity which was considered to be temporary at that time. We believed we would ultimately recover the par value of the ARPSs without a loss, primarily due to the collateral securing the ARPSs and our estimate of the discounted cash flows that we expected to collect. Also, we did not intend to sell the ARPSs at a loss and we believed it was more-likely-than-not that we would not have to sell prior to recovery of the ARPSs’ par value based on our liquidity needs. Therefore, the fair value discount of $2.7 million at December 31, 2009 was recorded as unrealized losses, net of tax, in accumulated other comprehensive income (loss) which was a component of shareholders’ equity. There were no portions of the fair value discounts attributable to credit losses.
The fair value of our long-term debt is estimated using a discounted cash flow analysis, based on rates that we believe we would currently pay for similar types of debt instruments. This discounted cash flow analysis is based on inputs defined by ASC Topic 820 as level 2 inputs, which are observable inputs for similar types of debt instruments represents level 2 inputs as defined by ASC Topic 820.instruments. The following table presents the supplemental fair value information about long-term debt at December 31, 20102013 and 2009December 31, 2012 (amounts in thousands): | | | | | | | | | | | | | | | | |
| | | December 31, 2010 | | | December 31, 2009 | |
| | | Carrying | | | Fair | | | Carrying | | | Fair | |
| | | Amount | | | Value | | | Amount | | | Value | |
Total debt | | $ | 280,938 | | | $ | 308,630 | | | $ | 262,114 | | | $ | 262,429 | |
| | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | |
| | December 31, 2013 | | December 31, 2012 |
| | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Total debt | $ | 502,513 |
| | $ | 538,074 |
| | $ | 519,597 |
| | $ | 565,257 |
|
7. | |
| 8. | Earnings (loss) Per Common Share |
The following table presents a reconciliation of the numerators and denominators of the basic
lossincome per share and diluted
lossincome per share
comparisons as required by ASC Topic 260computations (amounts in thousands, except per share data):
| | | | | | | | | | | | |
| | | Years ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
Basic | | | | | | | | | | | | |
Net loss | | $ | (33,261 | ) | | $ | (23,215 | ) | | $ | (62,745 | ) |
| | | | | | | | | | | | |
Weighted average shares | | | 53,797 | | | | 50,313 | | | | 49,789 | |
| | | | | | | | | | | | |
Loss per share | | $ | (0.62 | ) | | $ | (0.46 | ) | | $ | (1.26 | ) |
| | | | | | | | | | | | |
Diluted | | | | | | | | | | | | |
Net loss | | $ | (33,261 | ) | | $ | (23,215 | ) | | $ | (62,745 | ) |
Effect of dilutive securities | | | — | | | | — | | | | — | |
| | | | | | | | | | | | |
Net loss available to common shareholders after assumed conversion | | $ | (33,261 | ) | | $ | (23,215 | ) | | $ | (62,745 | ) |
| | | | | | | | | | | | |
Weighted average shares: | | | | | | | | | | | | |
Outstanding | | | 53,797 | | | | 50,313 | | | | 49,789 | |
Options | | | — | | | | — | | | | — | |
| | | | | | | | | | | | |
| | | 53,797 | | | | 50,313 | | | | 49,789 | |
| | | | | | | | | | | | |
Loss per share | | $ | (0.62 | ) | | $ | (0.46 | ) | | $ | (1.26 | ) |
| | | | | | | | | | | | |
Outstanding
|
| | | | | | | | | | | |
| | Year ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Basic | | | | | |
| Net income (loss) | $ | (35,932 | ) | | $ | 30,032 |
| | $ | 11,177 |
|
| Weighted-average shares | 62,213 |
| | 61,780 |
| | 57,390 |
|
| Income (loss) per share | $ | (0.58 | ) | | $ | 0.49 |
| | $ | 0.19 |
|
| Diluted | | | | | |
| Net income (loss) | $ | (35,932 | ) | | $ | 30,032 |
| | $ | 11,177 |
|
| Weighted average shares: | | | | | |
| Outstanding | 62,213 |
| | 61,780 |
| | 57,390 |
|
Diluted effect of stock options, restricted stock, and restricted stock unit awards | — |
| | 982 |
| | 1,389 |
|
| | 62,213 |
| | 62,762 |
| | 58,779 |
|
| Income (loss) per share | $ | (0.58 | ) | | $ | 0.48 |
| | $ | 0.19 |
|
Potentially dilutive stock options, restricted stock and restricted stock unit awards representing 852,370, 279,949a total of 5,507,765, 4,311,645 and 546,4292,430,141 shares of common stock for the years ended December 31, 2013, 2012 and 2011, respectively, were excluded from the computation of diluted loss per share calculations for the years ended December 31, 2010, 2009 and 2008, respectively, because the effect ofweighted average shares outstanding due to their inclusion would be anti-dilutive, or would decrease the reported loss per share.antidilutive effect. 8. | |
| 9. | Equity Transactions and Stock BasedStock-Based Compensation Plans |
On November 10, 2009,
Equity Transactions
In July 2011, we sold 3,820,000obtained $94.3 million in net proceeds from the sale of 6,900,000 shares of our common stock at $6.75$14.50 per share, less underwriters’ commissions and other offering costs, pursuant to a public offering under athe shelf registration statement.statement which we filed in July 2009.
In May 2012, we filed a registration statement that permits us to sell equity or debt in one or more offerings up to a total dollar amount of $300 million. As of December 31, 2013, the entire $300 million under the shelf registration statement is available for equity or debt offerings. In the future, we may consider equity or debt offerings, as appropriate, to meet our liquidity needs.
Stock-based Compensation Plans
We have stock basedstock-based award plans that are administered by the Compensation Committee of our Board of Directors, which selects persons eligible to receive awards and determines the number of stock options, restricted
stock, or restricted stock units subject to each award and the terms, conditions and other provisions of the awards. TotalAt December 31, 2013, the total shares available for future stock option grants, restricted stock grants, and restricted stock unit grants to employees and directors under existing plans were 960,521 at December 31, 2010. Of the total shares available,1,182,475, of which no more than 730,421 shares856,866 may be granted in the form of restricted stock.Prior to 2010, we granted stock-based compensation in the form ofstock or restricted stock unit awards.
We grant stock option awards and restricted stock awards with vesting based solely on time of service conditions. In 2010, we continued to grant stock option awards with vesting based on time of service conditions and we began grantingconditions. We also grant restricted stock unit awards with vesting based on time of service conditions, and in certain cases, subject to performance and market conditions. We recognize compensation cost for stock option, restricted stock and restricted stock unit awards based on the grant-date fair value estimated in accordance with ASC Topic 718, and utilizing theCompensation—Stock Compensation. For our awards with graded vesting, method.we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multiple awards.
The following table summarizes the compensation expense recognized for stock option, restricted stock and restricted stock unit awards during the years ended December 31, 2013, 2012 and 2011 (amounts in thousands):
|
| | | | | | | | | | | |
| | Year ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Stock option awards | $ | 1,771 |
| | $ | 2,962 |
| | $ | 3,720 |
|
| Restricted stock awards | 576 |
| | 628 |
| | 1,030 |
|
| Restricted stock unit awards | 4,024 |
| | 3,729 |
| | 1,955 |
|
| | $ | 6,371 |
| | $ | 7,319 |
| | $ | 6,705 |
|
We grant stock option awards which generally become exercisable over three- to five-year periods,a three-year period and expire ten years after the date of grant. Our stock-based compensation plans providerequire that all stock option awards must have an exercise price that is not less than the fair market value of our common stock on the date of grant. We issue shares of our common stock when vested stock option awards are exercised. We estimate the fair value of each option grant on the date of grant using a Black-Scholes options-pricingoption pricing model. The following table summarizes the assumptions used in the Black-Scholes option-pricingoption pricing model based on a weighted-average calculation for the years ended December 31, 2010, 20092013, 2012 and 2008: | | | | | | | | | | | | |
| | | Years ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
Expected volatility | | | 62 | % | | | 58 | % | | | 44 | % |
Risk-free interest rates | | | 2.6 | % | | | 2.1 | % | | | 2.7 | % |
Expected life in years | | | 5.61 | | | | 5.48 | | | | 3.72 | |
Grant-date fair value | | $ | 4.91 | | | $ | 2.09 | | | $ | 5.66 | |
|
| | | | | | | | |
| | Year ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Expected volatility | 66 | % | | 70 | % | | 65 | % |
| Risk-free interest rates | 1.0 | % | | 0.8 | % | | 1.5 | % |
| Expected life in years | 5.53 |
| | 5.12 |
| | 4.33 |
|
| Grant-date fair value | $4.36 | | $5.02 | | $4.69 |
The assumptions
aboveused in the Black-Scholes option pricing model are based on multiple factors, including historical exercise patterns of homogeneous groups with respect to exercise and post-vesting employment termination behaviors, expected future exercising patterns for these same homogeneous groups and volatility of our stock price. As we have not declared dividends since we became a public company, we did not use a dividend yield. In each case, the actual value that will be realized, if any, will depend on the future performance of our common stock and overall stock market conditions. There is no assurance the value an optionee actually realizes will be at or near the value we have estimated using the Black-Scholes options-pricing model.
The following table represents stock option activity from December 31, 20082011 through December 31, 2010: | | | | | | | | | | | | |
| | | Number of
Shares | | | Weighted-Average
Exercise Price
Per Share | | | Weighted-Average
Remaining Contract
Life in Years | |
Outstanding stock options as of December 31, 2008 | | | 3,769,695 | | | $ | 12.85 | | | | | |
Granted | | | 1,526,550 | | | | 3.96 | | | | | |
Forfeited | | | (240,632 | ) | | | 12.88 | | | | | |
| | | | | | | | | | | | |
Outstanding stock options as of December 31, 2009 | | | 5,055,613 | | | $ | 10.17 | | | | | |
Granted | | | 787,200 | | | | 8.64 | | | | | |
Forfeited | | | (90,634 | ) | | | 12.84 | | | | | |
Exercised | | | (63,900 | ) | | | 3.73 | | | | | |
| | | | | | | | | | | | |
Outstanding stock options as of December 31, 2010 | | | 5,688,279 | | | $ | 9.98 | | | | 6.81 | |
| | | | | | | | | | | | |
Stock options exercisable as of December 31, 2010 | | | 3,503,596 | | | $ | 11.25 | | | | 5.82 | |
| | | | | | | | | | | | |
The following table summarizes the compensation expense recognized for stock option awards during the years ended 2013
: |
| | | | | |
| | Number of Shares | | Weighted-Average Exercise Price Per Share | | Weighted-Average Remaining Contract Life in Years |
| Outstanding stock options as of December 31, 2011 | 5,563,348 | | $10.20 | | |
| Granted | 530,156 | | 8.72 | | |
| Forfeited | (271,097) | | 13.60 | | |
| Exercised | (172,416) | | 4.02 | | |
| Outstanding stock options as of December 31, 2012 | 5,649,991 | | $10.09 | | |
| Granted | 220,656 | | 7.58 | | |
| Forfeited | (67,500) | | 16.02 | | |
| Exercised | (270,934) | | 4.67 | | |
| Outstanding stock options as of December 31, 2013 | 5,532,213 | | $10.18 | | 5.1 |
| Stock options exercisable as of December 31, 2013 | 4,775,172 | | $10.45 | | 4.6 |
At December 31, 2010, 2009 and 2008 (amounts in thousands): | | | | | | | | | | | | |
| | | Years ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
General and administrative expense | | $ | 4,047 | | | $ | 4,290 | | | $ | 3,085 | |
Operating costs | | | 500 | | | | 971 | | | | 871 | |
| | | | | | | | | | | | |
| | $ | 4,547 | | | $ | 5,261 | | | $ | 3,956 | |
| | | | | | | | | | | | |
At December 31, 2010,2013
, the aggregate intrinsic value of stock options outstanding was $9.9$4.9 million and the aggregate intrinsic value of stock options exercisable was $5.0 million.$4.8 million. Intrinsic value is the difference between the exercise price of a stock option and the closing market price of our common stock, which was $8.81$8.01 on December 31, 2010.2013
. The following table summarizes our nonvested stock option activity from December 31, 20082011 through December 31, 2010: | | | | | | | | |
| | | Number of
Shares | | | Weighted-Average
Grant-Date
Fair Value
Per Share | |
Nonvested stock options as of December 31, 2008 | | | 2,027,763 | | | $ | 5.74 | |
Granted | | | 1,526,550 | | | | 2.09 | |
Vested | | | (831,539 | ) | | | 5.62 | |
Forfeited | | | (185,300 | ) | | | 4.73 | |
| | | | | | | | |
Nonvested stock options as of December 31, 2009 | | | 2,537,474 | | | $ | 3.65 | |
Granted | | | 787,200 | | | | 4.91 | |
Vested | | | (1,115,991 | ) | | | 4.19 | |
Forfeited | | | (24,000 | ) | | | 3.34 | |
| | | | | | | | |
Nonvested stock options as of December 31, 2010 | | | 2,184,683 | | | $ | 3.83 | |
| | | | | | | | |
2013
: |
| | | |
| | Number of Shares | | Weighted-Average Grant-Date Fair Value Per Share |
| Nonvested stock options as of December 31, 2011 | 1,531,237 | | $3.98 |
| Granted | 530,156 | | 5.02 |
| Vested | (901,817) | | 3.42 |
| Forfeited | (28,732) | | 4.74 |
| Nonvested stock options as of December 31, 2012 | 1,130,844 | | $4.89 |
| Granted | 220,656 | | 4.36 |
| Vested | (594,459) | | 4.88 |
| Nonvested stock options as of December 31, 2013 | 757,041 | | $4.74 |
At December 31, 2010,2013, there was $2.4$0.8 million of unrecognized compensation cost relating to stock options which areis expected to be recognized over a weighted-average period of 1.4 years.During the year ended December 31, 2010, employees exercised stock options for the purchase of 63,900 shares of common stock at prices ranging from $3.67 to $4.77 per share. Employees did not exercise any stock options during the year ending December 31, 2009. Employees exercised stock options for the purchase of 170,054 shares of common stock at prices ranging from $3.67 to $10.31 per share during the year December 31, 2008. We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the fair market value of our stock on the date of exercise over the exercise price of the options.
0.6 years. In accordance with ASC Topic 718, we reported all excess tax benefits resulting from the exercise of stock options as financing cash flows in our consolidated statement of cash flows.On February 2, 2011,
January 2014, our Board of Directors approved the grant of stock options representing 597,298221,440 shares of common stock to officers and employees that will vest over a three-yearthree-year period.
Historically, we have generally granted restricted stock awards that vest over a three-yearthree-year period with a fair value based on the closing price of our common stock on the date of the grant. However, beginning in 2013, we began granting restricted stock awards with a vesting period of one year. When restricted stock awards are granted, or when restricted stock unit awards are converted to restricted stock, shares of our common stock are considered issued, but subject to certain restrictions. The following table summarizes our restricted stock activity from December 31, 20082011 through December 31, 2010: | | | | | | | | |
| | | Number of
Shares | | | Weighted-Average
Grant-Date
Fair Value per Share | |
Nonvested restricted stock as of December 31, 2008 | | | 173,866 | | | $ | 17.07 | |
Granted | | | 326,748 | | | | 4.23 | |
Vested | | | (54,956 | ) | | | 17.07 | |
Forfeited | | | (18,300 | ) | | | 11.86 | |
| | | | | | | | |
Nonvested restricted stock as of December 31, 2009 | | | 427,358 | | | $ | 7.48 | |
Granted | | | 66,224 | | | | 6.04 | |
Vested | | | (160,223 | ) | | | 8.52 | |
Forfeited | | | (3,700 | ) | | | 9.20 | |
| | | | | | | | |
Nonvested restricted stock as of December 31, 2010 | | | 329,659 | | | $ | 6.66 | |
| | | | | | | | |
The following table summarizes the compensation expense recognized for restricted stock awards during the years ended 2013
: |
| | | |
| | Number of Shares | | Weighted-Average Grant-Date Fair Value per Share |
| Nonvested restricted stock as of December 31, 2011 | 281,836 | | $7.18 |
| Granted | 49,748 | | 8.04 |
| Vested | (184,081) | | 6.21 |
| Forfeited | (4,683) | | 8.86 |
| Nonvested restricted stock as of December 31, 2012 | 142,820 | | $8.67 |
| Granted | 61,248 | | 7.51 |
| Vested | (98,864) | | 8.47 |
| Nonvested restricted stock as of December 31, 2013 | 105,204 | | $8.18 |
At December 31, 2010, 2009 and 2008 (amounts in thousands): | | | | | | | | | | | | |
| | | Years ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
General and administrative expense | | $ | 1,119 | | | $ | 1,641 | | | $ | 532 | |
Operating costs | | | 145 | | | | 314 | | | | 109 | |
| | | | | | | | | | | | |
| | $ | 1,264 | | | $ | 1,955 | | | $ | 641 | |
| | | | | | | | | | | | |
At December 31, 2010,2013
, there was $0.7$0.3 million of unrecognized compensation cost relating to restricted stock awards which areis expected to be recognized over a weighted-average period of 1.4 years.0.5 years. We grant restricted stock unit awards with vesting based on time of service conditions only
(“time-based RSUs”), and we grant restricted stock unit awards with vesting based on time of service,
which are also subject to performance and
performance conditions.market conditions (“performance-based RSUs”). Shares of our common stock are issued to recipients of restricted stock units only when they have satisfied the applicable vesting conditions.
During the year ended December 31, 2010, we granted restricted stock unit awards with vesting based on time of service conditions. These restricted stock unit awards
Our time-based RSUs generally vest over a three-yearthree-year period, with fair values based on the closing price of our common stock on the date of grant.
Our performance-based RSUs generally cliff vest after 39 months from the date of grant and represent 72,120are granted at a target number of issuable shares, for which the final number of shares of common stock.stock is adjusted based on our actual achievement levels that are measured against predetermined performance conditions. The number of shares of common stock awarded will be based upon the Company’s achievement in certain performance conditions, as compared to a predefined peer group, over the performance period, generally three years.
Approximately one-third of the performance-based RSUs are subject to a market condition, based on total shareholder return, and therefore the fair value of these restricted stock unit awards is measured using a Monte Carlo simulation model. Compensation expense for awards with a market condition is reduced only for estimated forfeitures; no adjustment to expense is otherwise made, regardless of the number of shares issued, if any. The remaining two-thirds of the performance-based RSUs are subject to performance conditions, based on EBITDA and return on capital employed, and therefore the fair value is based on the closing price of our common stock on the date of grant.During the year ended December 31, 2010, we also granted restricted stock unit awards with vesting based on time of service and performance conditions. These restricted stock unit awards vest over a three-year period. The fair value of these restricted stock unit awards is computed based on the closing price of our common stock on the date of grant, andapplied to the estimated number of shares of common stock. The estimated number of shares of
common stockthat will be adjusted based on our actual achievement levels that are measured against predetermined performance conditions.awarded. Compensation costexpense ultimately recognized isfor awards with performance conditions will be equal to the fair value of the restricted stock unit award based on the actual outcome of the service and performance conditions.
We did not grant any
As of December 31, 2013, we estimated that our actual achievement level for the performance-based RSUs granted during 2011, 2012 and 2013 will be approximately 120%, 110% and 100% of the predetermined performance conditions, respectively. Therefore, the outstanding 673,762 restricted stock unit awards priorunits would be adjusted to 2010. represent
721,751 shares of our common stock if these achievement levels are maintained through the applicable performance periods.
The following table summarizes our restricted stock unit activity from December 31, 20092011 through December 31, 2010: | | | | | | | | | | | | | | | | |
| | | Time-Based Award | | | Performance-Based Award | |
| | | Number of
Time-Based
Award Units | | | Weighted-Average
Grant-Date
Fair Value per Unit | | | Number of
Performance-Based
Award Units | | | Weighted-Average
Grant-Date
Fair Value per Unit | |
Nonvested restricted stock units as of December 31, 2009 | | | — | | | $ | — | | | | — | | | $ | — | |
Granted | | | 72,120 | | | | 8.86 | | | | 194,680 | | | | 8.86 | |
Vested | | | — | | | | — | | | | — | | | | — | |
Forfeited | | | (5,040 | ) | | | 8.86 | | | | (2,160 | ) | | | 8.86 | |
| | | | | | | | | | | | | | | | |
Nonvested restricted stock units as of December 31, 2010 | | | 67,080 | | | $ | 8.86 | | | | 192,520 | | | $ | 8.86 | |
| | | | | | | | | | | | | | | | |
As of 2013
: |
| | | | | | | | | | | |
| | Time-Based Award | | Performance-Based Award |
| | Number of Time-Based Award Units | | Weighted-Average Grant-Date Fair Value per Unit | | Number of Performance-Based Award Units | | Weighted-Average Grant-Date Fair Value per Unit |
| Nonvested restricted stock units as of December 31, 2011 | 272,951 |
| | $10.76 | | 139,089 |
| | $10.23 |
| Granted | 356,813 |
| | 8.21 | | 221,495 |
| | 9.85 |
| Vested | (72,259) |
| | 10.07 |
| | — |
| | — |
|
| Forfeited | (25,979) |
| | 10.34 | | (5,533) |
| | 10.23 |
| Nonvested restricted stock units as of December 31, 2012 | 531,526 |
| | $9.16 | | 355,051 |
| | $9.99 |
| Granted | 406,027 |
| | 7.59 | | 346,731 |
| | 8.34 |
| Vested | (254,629) |
| | 9.82 | | — |
| | — |
|
| Forfeited | (55,212) |
| | 8.60 | | (28,020) |
| | 8.81 |
| Nonvested restricted stock units as of December 31, 2013 | 627,712 |
| | $7.93 | | 673,762 |
| | $9.19 |
At December 31, 2010, we estimated that our actual achievement level will be 80% of the predetermined performance conditions. Therefore, the outstanding 192,520 restricted stock units would be adjusted to represent 154,016 shares of our common stock.The following table summarizes the compensation expense recognized for restricted stock unit awards during the year ended December 31, 2010 (amounts in thousands):
| | | | |
| | | Year ended
December 31, 2010 | |
General and administrative expense | | $ | 748 | |
Operating costs | | | 116 | |
| | | | |
| | $ | 864 | |
| | | | |
At December 31, 2010,2013
, there was $0.9$4.8 million of unrecognized compensation cost relating to restricted stock unit awards which areis expected to be recognized over a weighted-average period of 2.1 years.On February 2, 2011,
1.3 years. In January 2014, our Board of Directors approved the grant of restricted stock units representing 249,382669,051 shares of common stock to officers and employees that will vest over a three-yearthree-year period. 9. | |
| 10. | Employee Benefit Plans and Insurance |
We maintain a 401(k) retirement plan for our eligible employees. Under this plan, we may make a matching contribution, on a discretionary basis, equal to a percentage of each eligible employee’s annual contribution, which we determine annually. Our matching contributions for the years ended December 31, 2010, 20092013, 2012 and 20082011 were $0.9$6.0 million $0.7, $4.6 million and $1.8$2.6 million, respectively. We maintain a self-insurance program, for major medical hospitalization and dentalhospitalization coverage for employees and their dependents, which is partially funded by employee payroll deductions. We have provided for both reported andclaims costs as well as incurred but not reported medical costs in the accompanying consolidated balance sheets. As of January 1, 2011, weWe have a maximum liability of $150,000$150,000 per employee/dependentcovered individual per year, up from$125,000 during 2010.year. Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company. PayrollInsurance premiums and employee related costdeductibles accruals at
December 31, 20102013 and 20092012 include $1.5$3.1 million and $1.0$2.5 million, respectively, for our estimate of incurred but unpaid costs related to the self-insurance portion of our health insurance. We are self-insured for up to $500,000$500,000 per incident for all workers’ compensation claims submitted by employees for on-the-job injuries. We have deductiblesa deductible of $250,000 and $100,000$250,000 per occurrence under both our general liability insurance and auto liability insurance, respectively.insurance. We accrue our workers’ compensation claim cost estimates based on historical claims development data and we accrue the cost of administrative services associated with claims processing. Insurance premiums and deductibles accruals at December 31, 20102013 and 20092012 include $6.6$7.3 million and $7.0$6.1 million, respectively, for our estimate of costs relative to the self-insured portion of our workers’ compensation, general liability and auto liability insurance. Based upon our past experience, management believes that we have adequately provided for potential losses. However, future multiple occurrences of serious injuries to employees could have a material adverse effect on our financial position and results of operations.
10. | |
| 11. | Segment Information |
At December 31, 2010, we had We have two operating segments referred to as the Drilling Services DivisionSegment and the Production Services DivisionSegment which is the basis management uses for making operating decisions and assessing performance. Prior to our acquisitions of the production services businesses from WEDGE and Competition on March 1, 2008, all our operations related to the
Drilling Services Division and we reported these operations in a single operating segment. The acquisitions of the production services businesses from WEDGE and Competition resulted in the formation of our Production Services Division (see Note 2,Acquisitions).Segment—Drilling Services Division—Our Drilling Services DivisionSegment provides contract land drilling services with its fleetto a diverse group of 71 drilling rigs in the following locations:
| | | | |
Drilling Division Locations
| | Rig
Count | |
South Texas
| | | 19 | |
East Texas
| | | 13 | |
West Texas
| | | 3 | |
North Dakota
| | | 9 | |
North Texas
| | | 3 | |
Utah
| | | 3 | |
Oklahoma
| | | 6 | |
Appalachia
| | | 7 | |
Colombia
| | | 8 | |
Production Services Division—Our Production Services Division provides a range of services to oil and gas exploration and production companies with its fleet of 62 drilling rigs which are currently assigned to the following divisions:
|
| | | |
| Drilling Division | | Rig Count |
| South Texas | | 14 |
|
| West Texas | | 18 |
|
| North Dakota | | 11 |
|
| Utah | | 7 |
|
| Appalachia | | 4 |
|
| Colombia | | 8 |
|
| | 62 |
|
Production Services Segment—Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services, wirelinecoiled tubing services, and fishing and rental services. Our production services operations are managed through locations concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, Mid-Continent, Rocky Mountainboth onshore and Appalachian states. Weoffshore. As of December 31, 2013, we have a premium fleet of 75109 well serviceservicing rigs consisting of seventyninety-nine 550 horsepower rigs fourand ten 600 horsepower rigs and one 400 horsepower rig.rigs. We provide wireline services and coiled tubing services with a fleet of 86119 wireline units and 13 coiled tubing units, and we provide rental services with approximately $13.5a gross book value of $17.3 million of in fishing and rental tools. The following tables set forth certain financial information for our two operating segments and corporate as of and for the year ended years ending December 31, 20102013, 2012 and 2011 (amounts in thousands): | | | | | | | | | | | | | | | | |
| | | As of and for the Year Ended December 31, 2010 | |
| | | Drilling
Services
Division | | | Production
Services
Division | | | Corporate | | | Total | |
Identifiable assets | | $ | 542,242 | | | $ | 261,777 | | | $ | 37,324 | | | $ | 841,343 | |
| | | | | | | | | | | | | | | | |
Revenues | | $ | 312,196 | | | $ | 175,014 | | | $ | — | | | $ | 487,210 | |
Operating costs | | | 227,136 | | | | 105,295 | | | | — | | | | 332,431 | |
| | | | | | | | | | | | | | | | |
Segment margin | | $ | 85,060 | | | $ | 69,719 | | | $ | — | | | $ | 154,779 | |
| | | | | | | | | | | | | | | | |
Depreciation and amortization | | $ | 92,800 | | | $ | 26,740 | | | $ | 1,271 | | | $ | 120,811 | |
Capital expenditures | | $ | 109,261 | | | $ | 25,411 | | | $ | 479 | | | $ | 135,151 | |
The following tables set forth certain financial information for our two operating segments and corporate as of and for the year ended December 31, 2009 (amounts in thousands):
| | | | | | | | | | | | | | | | |
| | | As of and for the Year Ended December 31, 2009 | |
| | | Drilling
Services
Division | | | Production
Services
Division | | | Corporate | | | Total | |
Identifiable assets | | $ | 536,858 | | | $ | 234,920 | | | $ | 53,177 | | | $ | 824,955 | |
| | | | | | | | | | | | | | | | |
Revenues | | $ | 219,751 | | | $ | 105,786 | | | $ | — | | | $ | 325,537 | |
Operating costs | | | 147,343 | | | | 68,012 | | | | — | | | | 215,355 | |
| | | | | | | | | | | | | | | | |
Segment margin | | $ | 72,408 | | | $ | 37,774 | | | $ | — | | | $ | 110,182 | |
| | | | | | | | | | | | | | | | |
Depreciation and amortization | | $ | 81,078 | | | $ | 23,893 | | | $ | 1,215 | | | $ | 106,186 | |
Capital expenditures | | $ | 94,887 | | | $ | 15,162 | | | $ | 404 | | | $ | 110,453 | |
|
| | | | | | | | | | | | | | | |
| | As of and for the year ended December 31, 2013 |
| | Drilling Services Segment | | Production Services Segment | | Corporate | | Total |
| Identifiable assets | $ | 791,820 |
| | $ | 395,219 |
| | $ | 42,584 |
| | $ | 1,229,623 |
|
| Revenues | $ | 528,327 |
| | $ | 431,859 |
| | $ | — |
| | $ | 960,186 |
|
| Operating costs | 351,630 |
| | 276,808 |
| | — |
| | 628,438 |
|
| Segment margin | $ | 176,697 |
| | $ | 155,051 |
| | $ | — |
| | $ | 331,748 |
|
| Depreciation and amortization | $ | 122,201 |
| | $ | 64,604 |
| | $ | 1,113 |
| | $ | 187,918 |
|
| Capital expenditures | $ | 78,708 |
| | $ | 44,541 |
| | $ | 2,171 |
| | $ | 125,420 |
|
|
| | | | | | | | | | | | | | | |
| | As of and for the year ended December 31, 2012 |
| | Drilling Services Segment | | Production Services Segment | | Corporate | | Total |
| Identifiable assets | $ | 867,526 |
| | $ | 439,113 |
| | $ | 33,137 |
| | $ | 1,339,776 |
|
| Revenues | $ | 498,867 |
| | $ | 420,576 |
| | $ | — |
| | $ | 919,443 |
|
| Operating costs | 333,846 |
| | 252,775 |
| | — |
| | 586,621 |
|
| Segment margin | $ | 165,021 |
| | $ | 167,801 |
| | $ | — |
| | $ | 332,822 |
|
| Depreciation and amortization | $ | 108,151 |
| | $ | 55,693 |
| | $ | 873 |
| | $ | 164,717 |
|
| Capital expenditures | $ | 265,966 |
| | $ | 110,813 |
| | $ | 2,493 |
| | $ | 379,272 |
|
|
| | | | | | | | | | | | | | | |
| | As of and for the year ended December 31, 2011 |
| | Drilling Services Segment | | Production Services Segment | | Corporate | | Total |
| Identifiable assets | $ | 667,588 |
| | $ | 398,128 |
| | $ | 107,038 |
| | $ | 1,172,754 |
|
| Revenues | $ | 433,902 |
| | $ | 282,039 |
| | $ | — |
| | $ | 715,941 |
|
| Operating costs | 292,559 |
| | 164,365 |
| | — |
| | 456,924 |
|
| Segment margin | $ | 141,343 |
| | $ | 117,674 |
| | $ | — |
| | $ | 259,017 |
|
| Depreciation and amortization | $ | 99,302 |
| | $ | 32,683 |
| | $ | 847 |
| | $ | 132,832 |
|
| Capital expenditures | $ | 168,120 |
| | $ | 68,908 |
| | $ | 759 |
| | $ | 237,787 |
|
The following table reconciles the segment profits reported above to income from operations as reported on the condensed consolidated statements of operations for the years ended December 31, 20102013, 2012 and 20092011 (amounts in thousands): | | | | | | | | |
| | | Year Ended
December 31, 2010 | | | Year Ended
December 31, 2009 | |
Segment margin | | $ | 154,779 | | | $ | 110,182 | |
Depreciation and amortization | | | (120,811 | ) | | | (106,186 | ) |
General and administrative | | | (52,047 | ) | | | (37,478 | ) |
Bad debt (expense) recovery | | | (493 | ) | | | 1,642 | |
| | | | | | | | |
Loss from operations | | $ | (18,572 | ) | | $ | (31,840 | ) |
| | | | | | | | |
|
| | | | | | | | | | | |
| | Year ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Segment margin | $ | 331,748 |
| | $ | 332,822 |
| | $ | 259,017 |
|
| Depreciation and amortization | (187,918 | ) | | (164,717 | ) | | (132,832 | ) |
| General and administrative | (95,000 | ) | | (85,603 | ) | | (67,318 | ) |
| Bad debt recovery (expense) | (767 | ) | | 440 |
| | (925 | ) |
| Impairment charges | (54,292 | ) | | (1,131 | ) | | (484 | ) |
| Income (loss) from operations | $ | (6,229 | ) | | $ | 81,811 |
| | $ | 57,458 |
|
The following table sets forth certain financial information for our international operations in Colombia as of and for the years ended December 31, 20102013, 2012 and 2009 which is included in our Drilling Services Division2011 (amounts in thousands): | | | | | | | | |
| | | As of and
for the
Year Ended
December 31, 2010 | | | As of and
for the
Year Ended
December 31, 2009 | |
Identifiable assets | | $ | 157,509 | | | $ | 120,319 | |
| | | | | | | | |
Revenues | | $ | 86,432 | | | $ | 56,617 | |
| | | | | | | | |
|
| | | | | | | | | | | |
| | As of and for the year ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Identifiable assets | $ | 150,719 |
| | $ | 148,567 |
| | $ | 151,448 |
|
| Revenues | $ | 115,631 |
| | $ | 95,338 |
| | $ | 109,539 |
|
Identifiable assets as of December 31, 2010for our international operations in Colombia include five drilling rigs that are owned by our Colombia subsidiary and three drilling rigs that are owned by one of our domestic subsidiaries and leased to our Colombia subsidiary. Identifiable assets as of December 31, 2009 include five drilling rigs that are owned by our Colombia subsidiary and one drilling rigs that is owned by one of our domestic subsidiaries and leased to our Colombia subsidiary. 11. | |
| 12. | Commitments and Contingencies |
In connection with our expansion into international markets,operations in Colombia, our foreign subsidiaries have obtained bonds for bidding on drilling contracts, performing under drilling contracts, and remitting customs and importation duties. We have guaranteed payments of $62.8$60.4 million relating to our performance under these bonds.The Colombian government enacted a tax reform act which, among other things, adopted a one-time, net-worth tax for all Colombian entities. The tax is assessed on an entity’s net equity, measured on a Colombian tax basisbonds as of January 1, 2011, and is payable in eight semi-annual installments from 2011 through 2014. Based on our Colombian operations’ net equity, as defined, we estimate that our total net-worth tax obligation is approximately $7.3 million, which is not deductible for tax purposes. In January 2011, the actual net-worth tax obligation will be recognized in full in other expense in our consolidated statement of operations and in other accrued expenses and other long-term liabilities on our consolidated balance sheet.
December 31, 2013. Due to the nature of our business, we are, from time to time, involved in litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. Legal costs relating to these matters are expensed as incurred. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition, results of operations or cash flow from operations.
12. | |
| 13. | Quarterly Results of Operations (unaudited) |
The following table summarizes quarterly financial data for the years ended December 31, 20102013 and December 31, 20092012 (in thousands, except per share data): | | | | | | | | | | | | | | | | | | | | |
Year Ended December 31, 2010 | | First
Quarter | | | Second
Quarter | | | Third
Quarter | | | Fourth
Quarter | | | Total | |
Revenues | | $ | 86,021 | | | $ | 117,027 | | | $ | 135,544 | | | $ | 148,618 | | | $ | 487,210 | |
Income (loss) from operations | | | (20,116 | ) | | | (7,856 | ) | | | 2,536 | | | | 6,864 | | | | (18,572 | ) |
Income tax (expense) benefit | | | 9,159 | | | | 4,498 | | | | 1,612 | | | | (972 | ) | | | 14,297 | |
Net loss | | | (14,547 | ) | | | (10,142 | ) | | | (2,580 | ) | | | (5,992 | ) | | | (33,261 | ) |
Loss per share: | | | | | | | | | | | | | | | | | | | | |
Basic | | $ | (0.27 | ) | | $ | (0.19 | ) | | $ | (0.05 | ) | | $ | (0.11 | ) | | $ | (0.62 | ) |
Diluted | | $ | (0.27 | ) | | $ | (0.19 | ) | | $ | (0.05 | ) | | $ | (0.11 | ) | | $ | (0.62 | ) |
| | | | | |
Year Ended December 31, 2009 | | | | | | | | | | | | | | | |
Revenues | | $ | 100,840 | | | $ | 69,120 | | | $ | 74,366 | | | $ | 81,211 | | | $ | 325,537 | |
Income (loss) from operations | | | 2,857 | | | | (9,273 | ) | | | (12,022 | ) | | | (13,402 | ) | | | (31,840 | ) |
Income tax expense | | | 180 | | | | 3,547 | | | | 4,406 | | | | 8,824 | | | | 16,957 | |
Net earnings (loss) | | | 618 | | | | (6,259 | ) | | | (9,190 | ) | | | (8,384 | ) | | | (23,215 | ) |
Earnings (loss) per share: | | | | | | | | | | | | | | | | | | | | |
Basic | | $ | 0.01 | | | $ | (0.13 | ) | | $ | (0.18 | ) | | $ | (0.16 | ) | | $ | (0.46 | ) |
Diluted | | $ | 0.01 | | | $ | (0.13 | ) | | $ | (0.18 | ) | | $ | (0.16 | ) | | $ | (0.46 | ) |
|
| | | | | | | | | | | | | | | | | | | |
| | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Total |
| Year ended December 31, 2013 | | | | | | | | | |
| Revenues | $ | 229,670 |
| | $ | 248,354 |
| | $ | 243,979 |
| | $ | 238,183 |
| | $ | 960,186 |
|
| Income (loss) from operations | 10,445 |
| | (27,268 | ) | | 1,870 |
| | 8,724 |
| | (6,229 | ) |
| Income tax (expense) benefit | 546 |
| | 14,953 |
| | 3,614 |
| | 733 |
| | 19,846 |
|
| Net income (loss) | (1,292 | ) | | (25,895 | ) | | (6,230 | ) | | (2,515 | ) | | (35,932 | ) |
| Earnings (loss) per share: | | | | | | | | | |
| Basic | $ | (0.02 | ) | | $ | (0.42 | ) | | $ | (0.10 | ) | | $ | (0.04 | ) | | $ | (0.58 | ) |
| Diluted | $ | (0.02 | ) | | $ | (0.42 | ) | | $ | (0.10 | ) | | $ | (0.04 | ) | | $ | (0.58 | ) |
| | | | | | | | | | |
| Year ended December 31, 2012 | | | | | | | | | |
| Revenues | $ | 231,978 |
| | $ | 229,824 |
| | $ | 229,773 |
| | $ | 227,868 |
| | $ | 919,443 |
|
| Income from operations | 29,748 |
| | 23,312 |
| | 13,222 |
| | 15,529 |
| | 81,811 |
|
| Income tax (expense) benefit | (6,953 | ) | | (5,997 | ) | | (1,461 | ) | | (1,943 | ) | | (16,354 | ) |
| Net income (loss) | 14,172 |
| | 9,685 |
| | 2,615 |
| | 3,560 |
| | 30,032 |
|
| Earnings (loss) per share: | | | | | | | | | |
| Basic | $ | 0.23 |
| | $ | 0.16 |
| | $ | 0.04 |
| | $ | 0.06 |
| | $ | 0.49 |
|
| Diluted | $ | 0.23 |
| | $ | 0.15 |
| | $ | 0.04 |
| | $ | 0.06 |
| | $ | 0.48 |
|
13. | |
| 14. | Guarantor/Non-Guarantor Condensed Consolidated Financial Statements |
Our Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by ourall existing domestic subsidiaries, except for Pioneer Services Holdings, LLC, and certain of our future domestic subsidiaries. Effective October 1, 2012, the Indenture was supplemented to add Pioneer Coiled Tubing Services, LLC (formerly Go-Coil, L.L.C.) as a subsidiary guarantor. The subsidiaries that generally operate our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. The non-guarantor subsidiaries do not have any payment obligations under the Senior Notes, the guarantees or the Indenture.
In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes. As of December 31, 2010,2013, there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company. As a result of the guarantee arrangements, we are presenting the following condensed consolidated balance sheets, statements of operations and statements of cash flows of the issuer, the guarantor subsidiaries and the non-guarantor subsidiaries.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited, in thousands) | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2010 | |
| | | Parent | | | Guarantor
Subsidiaries | | | Non-Guarantor
Subsidiaries | | | Eliminations | | | Consolidated | |
ASSETS | | | | | | | | | | | | | | | | | | | | |
Current assets: | | | | | | | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 15,737 | | | $ | (1,840 | ) | | $ | 8,114 | | | $ | — | | | $ | 22,011 | |
Short-term investments | | | 12,569 | | | | — | | | | — | | | | — | | | | 12,569 | |
Receivables | | | — | | | | 78,575 | | | | 10,940 | | | | — | | | | 89,515 | |
Intercompany receivable (payable) | | | (80,900 | ) | | | 80,942 | | | | (42 | ) | | | — | | | | — | |
Deferred income taxes | | | 178 | | | | 4,167 | | | | 5,522 | | | | — | | | | 9,867 | |
Inventory | | | — | | | | 2,874 | | | | 6,149 | | | | — | | | | 9,023 | |
Prepaid expenses and other current assets | | | 263 | | | | 4,604 | | | | 3,930 | | | | — | | | | 8,797 | |
| | | | | | | | | | | | | | | | | | | | |
Total current assets | | | (52,153 | ) | | | 169,322 | | | | 34,613 | | | | — | | | | 151,782 | |
| | | | | | | | | | | | | | | | | | | | |
Net property and equipment | | | 1,601 | | | | 562,390 | | | | 92,267 | | | | (750 | ) | | | 655,508 | |
Investment in subsidiaries | | | 714,292 | | | | 114,483 | | | | — | | | | (828,775 | ) | | | — | |
Intangible assets, net of amortization | | | 235 | | | | 21,731 | | | | — | | | | — | | | | 21,966 | |
Noncurrent deferred income taxes | | | 14,632 | | | | — | | | | — | | | | (14,632 | ) | | | — | |
Other long-term assets | | | 6,739 | | | | 2,844 | | | | 2,504 | | | | — | | | | 12,087 | |
| | | | | | | | | | | | | | | | | | | | |
Total assets | | $ | 685,346 | | | $ | 870,770 | | | $ | 129,384 | | | $ | (844,157 | ) | | $ | 841,343 | |
| | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | | | | | | | | | | | | | | | |
Current liabilities: | | | | | | | | | | | | | | | | | | | | |
Accounts payable | | $ | 242 | | | $ | 20,134 | | | $ | 6,553 | | | | — | | | $ | 26,929 | |
Current portion of long-term debt | | | 63 | | | | 1,345 | | | | — | | | | — | | | | 1,408 | |
Prepaid drilling contracts | | | — | | | | 1,000 | | | | 2,669 | | | | — | | | | 3,669 | |
Accrued expenses | | | 9,861 | | | | 30,786 | | | | 2,987 | | | | — | | | | 43,634 | |
| | | | | | | | | | | | | | | | | | | | |
Total current liabilities | | | 10,166 | | | | 53,265 | | | | 12,209 | | | | — | | | | 75,640 | |
Long-term debt, less current portion | | | 277,830 | | | | 1,700 | | | | — | | | | — | | | | 279,530 | |
Other long-term liabilities | | | 267 | | | | 6,744 | | | | 2,669 | | | | — | | | | 9,680 | |
Deferred income taxes | | | — | | | | 94,769 | | | | 23 | | | | (14,632 | ) | | | 80,160 | |
| | | | | | | | | | | | | | | | | | | | |
Total liabilities | | | 288,263 | | | | 156,478 | | | | 14,901 | | | | (14,632 | ) | | | 445,010 | |
Total shareholders’ equity | | | 397,083 | | | | 714,292 | | | | 114,483 | | | | (829,525 | ) | | | 396,333 | |
| | | | | | | | | | | | | | | | | | | | |
Total liabilities and shareholders’ equity | | $ | 685,346 | | | $ | 870,770 | | | $ | 129,384 | | | $ | (844,157 | ) | | $ | 841,343 | |
| | | | | | | | | | | | | | | | | | | | |
| |
| | | December 31, 2009 | |
| | | Parent | | | Guarantor
Subsidiaries | | | Non-Guarantor
Subsidiaries | | | Eliminations | | | Consolidated | |
ASSETS | | | | | | | | | | | | | | | | | | | | |
Current assets: | | | | | | | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 33,352 | | | $ | (2,716 | ) | | $ | 9,743 | | | $ | — | | | $ | 40,379 | |
Receivables | | | — | | | | 76,490 | | | | 4,977 | | | | — | | | | 81,467 | |
Intercompany receivable (payable) | | | (86,442 | ) | | | 86,663 | | | | (221 | ) | | | — | | | | — | |
Deferred income taxes | | | — | | | | 3,909 | | | | 1,651 | | | | — | | | | 5,560 | |
Inventory | | | — | | | | 1,791 | | | | 3,744 | | | | — | | | | 5,535 | |
Prepaid expenses and other current assets | | | 224 | | | | 4,008 | | | | 1,967 | | | | — | | | | 6,199 | |
| | | | | | | | | | | | | | | | | | | | |
Total current assets | | | (52,866 | ) | | | 170,145 | | | | 21,861 | | | | — | | | | 139,140 | |
| | | | | | | | | | | | | | | | | | | | |
Net property and equipment | | | 1,898 | | | | 550,730 | | | | 85,143 | | | | (749 | ) | | | 637,022 | |
Investment in subsidiaries | | | 712,720 | | | | 104,256 | | | | — | | | | (816,976 | ) | | | — | |
Intangible assets, net of amortization | | | 698 | | | | 24,695 | | | | — | | | | — | | | | 25,393 | |
Noncurrent deferred income taxes | | | 980 | | | | 11 | | | | 2,339 | | | | (991 | ) | | | 2,339 | |
Long-term investments | | | 13,228 | | | | — | | | | — | | | | — | | | | 13,228 | |
Other long-term assets | | | 3,779 | | | | 3,561 | | | | 493 | | | | — | | | | 7,833 | |
| | | | | | | | | | | | | | | | | | | | |
Total assets | | $ | 680,437 | | | $ | 853,398 | | | $ | 109,836 | | | $ | (818,716 | ) | | $ | 824,955 | |
| | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | | | | | | | | | | | | | | | |
Current liabilities: | | | | | | | | | | | | | | | | | | | | |
Accounts payable | | $ | 286 | | | $ | 12,277 | | | $ | 2,761 | | | $ | — | | | $ | 15,324 | |
Current portion of long-term debt | | | 2,100 | | | | 1,941 | | | | — | | | | — | | | | 4,041 | |
Prepaid drilling contracts | | | — | | | | 324 | | | | 84 | | | | — | | | | 408 | |
Accrued expenses | | | 226 | | | | 26,070 | | | | 2,735 | | | | — | | | | 29,031 | |
| | | | | | | | | | | | | | | | | | | | |
Total current liabilities | | | 2,612 | | | | 40,612 | | | | 5,580 | | | | — | | | | 48,804 | |
Long-term debt, less current portion | | | 255,628 | | | | 2,445 | | | | — | | | | — | | | | 258,073 | |
Other long-term liabilities | | | — | | | | 6,457 | | | | — | | | | — | | | | 6,457 | |
Deferred income taxes | | | — | | | | 91,164 | | | | — | | | | (991 | ) | | | 90,173 | |
| | | | | | | | | | | | | | | | | | | | |
Total liabilities | | | 258,240 | | | | 140,678 | | | | 5,580 | | | | (991 | ) | | | 403,507 | |
Total shareholders’ equity | | | 422,197 | | | | 712,720 | | | | 104,256 | | | | (817,725 | ) | | | 421,448 | |
| | | | | | | | | | | | | | | | | | | | |
Total liabilities and shareholders’ equity | | $ | 680,437 | | | $ | 853,398 | | | $ | 109,836 | | | $ | (818,716 | ) | | $ | 824,955 | |
| | | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2013 |
| | Parent | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated |
| ASSETS | | | | | | | | | |
| Current assets: | | | | | | | | | |
| Cash and cash equivalents | $ | 28,368 |
| | $ | (2,059 | ) | | $ | 1,076 |
| | $ | — |
| | $ | 27,385 |
|
| Receivables, net of allowance | 905 |
| | 125,979 |
| | 49,476 |
| | — |
| | 176,360 |
|
| Intercompany receivable (payable) | (24,837 | ) | | 52,671 |
| | (27,834 | ) | | — |
| | — |
|
| Deferred income taxes | 1,143 |
| | 8,005 |
| | 3,944 |
| | — |
| | 13,092 |
|
| Inventory | — |
| | 7,415 |
| | 5,817 |
| | — |
| | 13,232 |
|
| Prepaid expenses and other current assets | 1,013 |
| | 7,094 |
| | 1,204 |
| | — |
| | 9,311 |
|
| Total current assets | 6,592 |
| | 199,105 |
| | 33,683 |
| | — |
| | 239,380 |
|
| Net property and equipment | 4,531 |
| | 846,632 |
| | 87,244 |
| | (750 | ) | | 937,657 |
|
| Investment in subsidiaries | 939,091 |
| | 120,630 |
| | — |
| | (1,059,721 | ) | | — |
|
| Intangible assets, net of accumulated amortization | 75 |
| | 32,194 |
| | — |
| | — |
| | 32,269 |
|
| Noncurrent deferred income taxes | 78,486 |
| | — |
| | 1,156 |
| | (78,486 | ) | | 1,156 |
|
| Other long-term assets | 7,513 |
| | 2,009 |
| | 9,639 |
| | — |
| | 19,161 |
|
| Total assets | $ | 1,036,288 |
| | $ | 1,200,570 |
| | $ | 131,722 |
| | $ | (1,138,957 | ) | | $ | 1,229,623 |
|
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | | | | |
| Current liabilities: | | | | | | | | | |
| Accounts payable | $ | 757 |
| | $ | 37,797 |
| | $ | 5,164 |
| | — |
| | $ | 43,718 |
|
| Current portion of long-term debt | — |
| | 2,847 |
| | — |
| | — |
| | 2,847 |
|
| Deferred revenues | — |
| | 699 |
| | — |
| | — |
| | 699 |
|
| Accrued expenses | 16,368 |
| | 51,739 |
| | 5,462 |
| | — |
| | 73,569 |
|
| Total current liabilities | 17,125 |
| | 93,082 |
| | 10,626 |
| | — |
| | 120,833 |
|
| Long-term debt, less current portion | 499,586 |
| | 80 |
| | — |
| | — |
| | 499,666 |
|
| Noncurrent deferred income taxes | — |
| | 163,122 |
| | — |
| | (78,486 | ) | | 84,636 |
|
| Other long-term liabilities | 394 |
| | 5,195 |
| | 466 |
| | — |
| | 6,055 |
|
| Total liabilities | 517,105 |
| | 261,479 |
| | 11,092 |
| | (78,486 | ) | | 711,190 |
|
| Total shareholders’ equity | 519,183 |
| | 939,091 |
| | 120,630 |
| | (1,060,471 | ) | | 518,433 |
|
| Total liabilities and shareholders’ equity | $ | 1,036,288 |
| | $ | 1,200,570 |
| | $ | 131,722 |
| | $ | (1,138,957 | ) | | $ | 1,229,623 |
|
| | | | | | | | | | |
| | December 31, 2012 |
| | Parent | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated |
| ASSETS | | | | | | | | | |
| Current assets: | | | | | | | | | |
| Cash and cash equivalents | $ | 18,479 |
| | $ | (5,401 | ) | | $ | 10,655 |
| | $ | — |
| | $ | 23,733 |
|
| Receivables, net of allowance | 440 |
| | 129,570 |
| | 29,128 |
| | (294 | ) | | 158,844 |
|
| Intercompany receivable (payable) | (124,516 | ) | | 146,652 |
| | (22,136 | ) | | — |
| | — |
|
| Deferred income taxes | 869 |
| | 8,162 |
| | 2,027 |
| | — |
| | 11,058 |
|
| Inventory | — |
| | 5,956 |
| | 6,155 |
| | — |
| | 12,111 |
|
| Prepaid expenses and other current assets | 655 |
| | 9,163 |
| | 3,222 |
| | — |
| | 13,040 |
|
| Total current assets | (104,073 | ) | | 294,102 |
| | 29,051 |
| | (294 | ) | | 218,786 |
|
| Net property and equipment | 3,474 |
| | 921,393 |
| | 90,223 |
| | (750 | ) | | 1,014,340 |
|
| Investment in subsidiaries | 1,122,814 |
| | 114,416 |
| | — |
| | (1,237,230 | ) | | — |
|
| Intangible assets, net of accumulated amortization | 68 |
| | 43,775 |
| | — |
| | — |
| | 43,843 |
|
| Goodwill | — |
| | 41,683 |
| | — |
| | — |
| | 41,683 |
|
| Noncurrent deferred income taxes | 51,834 |
| | — |
| | 5,519 |
| | (51,834 | ) | | 5,519 |
|
| Other long-term assets | 9,582 |
| | 2,340 |
| | 3,683 |
| | — |
| | 15,605 |
|
| Total assets | $ | 1,083,699 |
| | $ | 1,417,709 |
| | $ | 128,476 |
| | $ | (1,290,108 | ) | | $ | 1,339,776 |
|
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | | | | |
| Current liabilities: | | | | | | | | | |
| Accounts payable | $ | 1,558 |
| | $ | 76,828 |
| | $ | 5,437 |
| | $ | — |
| | $ | 83,823 |
|
| Current portion of long-term debt | — |
| | 872 |
| | — |
| | — |
| | 872 |
|
| Deferred revenues | — |
| | 1,954 |
| | 1,926 |
| | — |
| | 3,880 |
|
| Accrued expenses | 14,905 |
| | 48,892 |
| | 4,472 |
| | (294 | ) | | 67,975 |
|
| Total current liabilities | 16,463 |
| | 128,546 |
| | 11,835 |
| | (294 | ) | | 156,550 |
|
| Long-term debt, less current portion | 518,618 |
| | 107 |
| | — |
| | — |
| | 518,725 |
|
| Noncurrent deferred income taxes | (4 | ) | | 160,676 |
| | — |
| | (51,834 | ) | | 108,838 |
|
| Other long-term liabilities | 192 |
| | 5,566 |
| | 2,225 |
| | — |
| | 7,983 |
|
| Total liabilities | 535,269 |
| | 294,895 |
| | 14,060 |
| | (52,128 | ) | | 792,096 |
|
| Total shareholders’ equity | 548,430 |
| | 1,122,814 |
| | 114,416 |
| | (1,237,980 | ) | | 547,680 |
|
| Total liabilities and shareholders’ equity | $ | 1,083,699 |
| | $ | 1,417,709 |
| | $ | 128,476 |
| | $ | (1,290,108 | ) | | $ | 1,339,776 |
|
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands) | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2010 | |
| | | Parent | | | Guarantor
Subsidiaries | | | Non-Guarantor
Subsidiaries | | | Eliminations | | | Consolidated | |
Revenues: | | $ | — | | | $ | 400,778 | | | $ | 86,432 | | | $ | — | | | $ | 487,210 | |
| | | | | | | | | | | | | | | | | | | | |
Costs and expenses: | | | | | | | | | | | | | | | | | | | | |
Operating costs | | | — | | | | 263,649 | | | | 68,782 | | | | — | | | | 332,431 | |
Depreciation and amortization | | | 1,271 | | | | 109,971 | | | | 9,569 | | | | — | | | | 120,811 | |
General and administrative | | | 15,337 | | | | 34,177 | | | | 2,959 | | | | (426 | ) | | | 52,047 | |
Intercompany leasing | | | — | | | | (4,323 | ) | | | 4,323 | | | | — | | | | — | |
Bad debt recovery | | | — | | | | 493 | | | | — | | | | — | | | | 493 | |
| | | | | | | | | | | | | | | | | | | | |
Total costs and expenses | | | 16,608 | | | | 403,967 | | | | 85,633 | | | | (426 | ) | | | 505,782 | |
| | | | | | | | | | | | | | | | | | | | |
Income (loss) from operations | | | (16,608 | ) | | | (3,189 | ) | | | 799 | | | | 426 | | | | (18,572 | ) |
| | | | | | | | | | | | | | | | | | | | |
Other income (expense): | | | | | | | | | | | | | | | | | | | | |
Equity in earnings of subsidiaries | | | (1,982 | ) | | | 1,335 | | | | — | | | | 647 | | | | — | |
Interest expense | | | (26,240 | ) | | | (399 | ) | | | (20 | ) | | | — | | | | (26,659 | ) |
Interest income | | | — | | | | 66 | | | | 26 | | | | — | | | | 92 | |
Impairment of investments | | | (3,331 | ) | | | — | | | | — | | | | — | | | | (3,331 | ) |
Other | | | — | | | | 953 | | | | 385 | | | | (426 | ) | | | 912 | |
| | | | | | | | | | | | | | | | | | | | |
Total other income (expense) | | | (31,553 | ) | | | 1,955 | | | | 391 | | | | 221 | | | | (28,986 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income (loss) before income taxes | | | (48,161 | ) | | | (1,234 | ) | | | 1,190 | | | | 647 | | | | (47,558 | ) |
Income tax benefit (expense) | | | 14,900 | | | | (748 | ) | | | 145 | | | | — | | | | 14,297 | |
| | | | | | | | | | | | | | | | | | | | |
Net earnings (loss) | | $ | (33,261 | ) | | $ | (1,982 | ) | | $ | 1,335 | | | $ | 647 | | | $ | (33,261 | ) |
| | | | | | | | | | | | | | | | | | | | |
| |
| | | Year Ended December 31, 2009 | |
| | | Parent | | | Guarantor
Subsidiaries | | | Non-Guarantor
Subsidiaries | | | Eliminations | | | Consolidated | |
Revenues: | | $ | — | | | $ | 268,920 | | | $ | 56,617 | | | $ | — | | | $ | 325,537 | |
| | | | | | | | | | | | | | | | | | | | |
Costs and expenses: | | | | | | | | | | | | | | | | | | | | |
Operating costs | | | — | | | | 174,579 | | | | 41,091 | | | | (315 | ) | | | 215,355 | |
Depreciation and amortization | | | 1,215 | | | | 97,015 | | | | 7,956 | | | | — | | | | 106,186 | |
General and administrative | | | 12,222 | | | | 25,293 | | | | 1,379 | | | | (1,416 | ) | | | 37,478 | |
Bad debt recovery | | | — | | | | (1,642 | ) | | | — | | | | — | | | | (1,642 | ) |
| | | | | | | | | | | | | | | | | | | | |
Total costs and expenses | | | 13,437 | | | | 295,245 | | | | 50,426 | | | | (1,731 | ) | | | 357,377 | |
| | | | | | | | | | | | | | | | | | | | |
Income (loss) from operations | | | (13,437 | ) | | | (26,325 | ) | | | 6,191 | | | | 1,731 | | | | (31,840 | ) |
| | | | | | | | | | | | | | | | | | | | |
Other income (expense): | | | | | | | | | | | | | | | | | | | | |
Equity in earnings of subsidiaries | | | (2,250 | ) | | | 9,245 | | | | — | | | | (6,995 | ) | | | — | |
Interest expense | | | (8,585 | ) | | | (555 | ) | | | (5 | ) | | | — | | | | (9,145 | ) |
Interest income | | | 1 | | | | 111 | | | | 105 | | | | — | | | | 217 | |
Other | | | 1,056 | | | | 1,362 | | | | (91 | ) | | | (1,731 | ) | | | 596 | |
| | | | | | | | | | | | | | | | | | | | |
Total other income (expense) | | | (9,778 | ) | | | 10,163 | | | | 9 | | | | (8,726 | ) | | | (8,332 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income (loss) before income taxes | | | (23,215 | ) | | | (16,162 | ) | | | 6,200 | | | | (6,995 | ) | | | (40,172 | ) |
Income tax benefit (expense) | | | — | | | | 13,912 | | | | 3,045 | | | | — | | | | 16,957 | |
| | | | | | | | | | | | | | | | | | | | |
Net earnings (loss) | | $ | (23,215 | ) | | $ | (2,250 | ) | | $ | 9,245 | | | $ | (6,995 | ) | | $ | (23,215 | ) |
| | | | | | | | | | | | | | | | | | | | |
| |
| | | Year Ended December 31, 2008 | |
| | | Parent | | | Guarantor
Subsidiaries | | | Non-Guarantor
Subsidiaries | | | Eliminations | | | Consolidated | |
Revenues: | | $ | — | | | $ | 559,470 | | | $ | 51,414 | | | $ | — | | | $ | 610,884 | |
| | | | | | | | | | | | | | | | | | | | |
Costs and expenses: | | | | | | | | | | | | | | | | | | | | |
Operating costs | | | — | | | | 313,319 | | | | 37,254 | | | | (630 | ) | | | 349,943 | |
Depreciation and amortization | | | 830 | | | | 82,252 | | | | 5,063 | | | | — | | | | 88,145 | |
General and administrative | | | 17,483 | | | | 27,011 | | | | 1,435 | | | | (1,095 | ) | | | 44,834 | |
Bad debt recovery | | | — | | | | 423 | | | | — | | | | — | | | | 423 | |
Impairment of goodwill | | | — | | | | 118,646 | | | | — | | | | — | | | | 118,646 | |
Impairment of intangible assets | | | — | | | | 52,847 | | | | — | | | | — | | | | 52,847 | |
| | | | | | | | | | | | | | | | | | | | |
Total costs and expenses | | | 18,313 | | | | 594,498 | | | | 43,752 | | | | (1,725 | ) | | | 654,838 | |
| | | | | | | | | | | | | | | | | | | | |
Income (loss) from operations | | | (18,313 | ) | | | (35,028 | ) | | | 7,662 | | | | 1,725 | | | | (43,954 | ) |
| | | | | | | | | | | | | | | | | | | | |
Other income (expense): | | | | | | | | | | | | | | | | | | | | |
Equity in earnings of subsidiaries | | | (32,531 | ) | | | 5,483 | | | | — | | | | 27,048 | | | | — | |
Interest expense | | | (12,523 | ) | | | (547 | ) | | | (2 | ) | | | — | | | | (13,072 | ) |
Interest income | | | 5 | | | | 1,143 | | | | 108 | | | | — | | | | 1,256 | |
Other | | | 675 | | | | 1,647 | | | | (1,451 | ) | | | (1,789 | ) | | | (918 | ) |
| | | | | | | | | | | | | | | | | | | | |
Total other income (expense) | | | (44,374 | ) | | | 7,726 | | | | (1,345 | ) | | | 25,259 | | | | (12,734 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income (loss) before income taxes | | | (62,687 | ) | | | (27,302 | ) | | | 6,317 | | | | 26,984 | | | | (56,688 | ) |
Income tax benefit (expense) | | | 6 | | | | (5,229 | ) | | | (834 | ) | | | — | | | | (6,057 | ) |
| | | | | | | | | | | | | | | | | | | | |
Net earnings (loss) | | $ | (62,681 | ) | | $ | (32,531 | ) | | $ | 5,483 | | | $ | 26,984 | | | $ | (62,745 | ) |
| | | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| | Year ended December 31, 2013 |
| | Parent | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated |
| Revenues | $ | — |
| | $ | 844,555 |
| | $ | 115,631 |
| | $ | — |
| | $ | 960,186 |
|
| Costs and expenses: | | | | | | | | | |
| Operating costs | — |
| | 547,528 |
| | 80,910 |
| | — |
| | 628,438 |
|
| Depreciation and amortization | 1,113 |
| | 173,516 |
| | 13,289 |
| | — |
| | 187,918 |
|
| General and administrative | 25,272 |
| | 66,779 |
| | 3,501 |
| | (552 | ) | | 95,000 |
|
| Intercompany leasing | — |
| | (4,860 | ) | | 4,860 |
| | — |
| | — |
|
| Bad debt expense (recovery) | 67 |
| | 700 |
| | — |
| | — |
| | 767 |
|
| Impairment charges | — |
| | 54,292 |
| | — |
| | — |
| | 54,292 |
|
| Total costs and expenses | 26,452 |
| | 837,955 |
| | 102,560 |
| | (552 | ) | | 966,415 |
|
| Income (loss) from operations | (26,452 | ) | | 6,600 |
| | 13,071 |
| | 552 |
| | (6,229 | ) |
| Other (expense) income: | | | | | | | | | |
| Equity in earnings of subsidiaries | 11,861 |
| | 6,260 |
| | — |
| | (18,121 | ) | | — |
|
| Interest expense | (48,302 | ) | | (37 | ) | | 29 |
| | — |
| | (48,310 | ) |
| Other | 9 |
| | 1,990 |
| | (2,686 | ) | | (552 | ) | | (1,239 | ) |
| Total other (expense) income | (36,432 | ) | | 8,213 |
| | (2,657 | ) | | (18,673 | ) | | (49,549 | ) |
| Income (loss) before income taxes | (62,884 | ) | | 14,813 |
| | 10,414 |
| | (18,121 | ) | | (55,778 | ) |
| Income tax (expense) benefit | 26,952 |
| | (2,952 | ) | | (4,154 | ) | | — |
| | 19,846 |
|
| Net income (loss) | $ | (35,932 | ) | | $ | 11,861 |
| | $ | 6,260 |
| | $ | (18,121 | ) | | $ | (35,932 | ) |
| | | | | | | | | | |
| | Year ended December 31, 2012 |
| | Parent | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated |
| Revenues | $ | — |
| | $ | 779,163 |
| | $ | 140,280 |
| | $ | — |
| | $ | 919,443 |
|
| Costs and expenses: | | | | | | | | | |
| Operating costs | — |
| | 485,342 |
| | 101,279 |
| | — |
| | 586,621 |
|
| Depreciation and amortization | 873 |
| | 142,972 |
| | 20,872 |
| | — |
| | 164,717 |
|
| General and administrative | 22,212 |
| | 54,715 |
| | 9,228 |
| | (552 | ) | | 85,603 |
|
| Intercompany leasing | — |
| | (4,860 | ) | | 4,860 |
| | — |
| | — |
|
| Bad debt expense (recovery) | — |
| | (612 | ) | | 172 |
| | — |
| | (440 | ) |
| Impairment charges | — |
| | 1,131 |
| | — |
| | — |
| | 1,131 |
|
| Total costs and expenses | 23,085 |
| | 678,688 |
| | 136,411 |
| | (552 | ) | | 837,632 |
|
| Income (loss) from operations | (23,085 | ) | | 100,475 |
| | 3,869 |
| | 552 |
| | 81,811 |
|
| Other (expense) income: | | | | | | | | | |
| Equity in earnings of subsidiaries | 68,352 |
| | 4,029 |
| | — |
| | (72,381 | ) | | — |
|
| Interest expense | (37,011 | ) | | (59 | ) | | 21 |
| | — |
| | (37,049 | ) |
| Other | 268 |
| | 940 |
| | 968 |
| | (552 | ) | | 1,624 |
|
| Total other (expense) income | 31,609 |
| | 4,910 |
| | 989 |
| | (72,933 | ) | | (35,425 | ) |
| Income (loss) before income taxes | 8,524 |
| | 105,385 |
| | 4,858 |
| | (72,381 | ) | | 46,386 |
|
| Income tax (expense) benefit | 21,508 |
| | (37,033 | ) | | (829 | ) | | — |
| | (16,354 | ) |
| Net income (loss) | $ | 30,032 |
| | $ | 68,352 |
| | $ | 4,029 |
| | $ | (72,381 | ) | | $ | 30,032 |
|
| | | | | | | | | | |
| | Year ended December 31, 2011 |
| | Parent | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated |
| Revenues | $ | — |
| | $ | 606,402 |
| | $ | 109,539 |
| | $ | — |
| | $ | 715,941 |
|
| Costs and expenses: | | | | | | | | | |
| Operating costs | — |
| | 372,945 |
| | 83,979 |
| | — |
| | 456,924 |
|
| Depreciation and amortization | 847 |
| | 119,520 |
| | 12,465 |
| | — |
| | 132,832 |
|
| General and administrative | 19,797 |
| | 45,152 |
| | 2,921 |
| | (552 | ) | | 67,318 |
|
| Intercompany leasing | — |
| | (4,860 | ) | | 4,857 |
| | 3 |
| | — |
|
| Bad debt expense (recovery) | — |
| | 925 |
| | — |
| | — |
| | 925 |
|
| Impairment of equipment | — |
| | 484 |
| | — |
| | — |
| | 484 |
|
| Total costs and expenses | 20,644 |
| | 534,166 |
| | 104,222 |
| | (549 | ) | | 658,483 |
|
| Income (loss) from operations | (20,644 | ) | | 72,236 |
| | 5,317 |
| | 549 |
| | 57,458 |
|
| Other (expense) income: | | | | | | | | | |
| Equity in earnings of subsidiaries | 43,182 |
| | (2,982 | ) | | — |
| | (40,200 | ) | | — |
|
| Interest expense | (29,497 | ) | | (248 | ) | | 24 |
| | — |
| | (29,721 | ) |
| Other | 311 |
| | 1,163 |
| | (7,829 | ) | | (549 | ) | | (6,904 | ) |
| Total other (expense) income | 13,996 |
| | (2,067 | ) | | (7,805 | ) | | (40,749 | ) | | (36,625 | ) |
| Income (loss) before income taxes | (6,648 | ) | | 70,169 |
| | (2,488 | ) | | (40,200 | ) | | 20,833 |
|
| Income tax expense (benefit) | 17,825 |
| | (26,987 | ) | | (494 | ) | | — |
| | (9,656 | ) |
| Net income (loss) | $ | 11,177 |
| | $ | 43,182 |
| | $ | (2,982 | ) | | $ | (40,200 | ) | | $ | 11,177 |
|
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)
| | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2010 | |
| | | Parent | | | Guarantor
Subsidiaries | | | Non-Guarantor
Subsidiaries | | | Eliminations | | | Consolidated | |
Cash flows from operating activities: | | $ | 31,841 | | | $ | 115,650 | | | $ | 14,542 | | | $ | — | | | $ | 98,351 | |
| | | | | | | | | | | | | | | | | | | | |
Cash flows from investing activities: | | | | | | | | | | | | | | | | | | | | |
Acquisition of other production services businesses | | | — | | | | (1,340 | ) | | | — | | | | — | | | | (1,340 | ) |
Purchases of property and equipment | | | (478 | ) | | | (114,313 | ) | | | (16,212 | ) | | | — | | | | (131,003 | ) |
Proceeds from sale of property and equipment | | | — | | | | 2,290 | | | | 41 | | | | — | | | | 2,331 | |
Proceeds from insurance recoveries | | | — | | | | 531 | | | | — | | | | — | | | | 531 | |
| | | | | | | | | | | | | | | | | | | | |
| | | (478 | ) | | | (112,832 | ) | | | (16,171 | ) | | | — | | | | (129,481 | ) |
| | | | | | | | | | | | | | | | | | | | |
Cash flows from financing activities: | | | | | | | | | | | | | | | | | | | | |
Debt repayments | | | (254,914 | ) | | | (1,942 | ) | | | — | | | | — | | | | (256,856 | ) |
Proceeds from issuance of debt | | | 274,375 | | | | — | | | | — | | | | — | | | | 274,375 | |
Debt issuance costs | | | (4,865 | ) | | | — | | | | — | | | | — | | | | (4,865 | ) |
Proceeds from exercise of options | | | 238 | | | | — | | | | — | | | | — | | | | 238 | |
Purchase of treasury stock | | | (130 | ) | | | — | | | | — | | | | — | | | | (130 | ) |
| | | | | | | | | | | | | | | | | | | | |
| | | 14,704 | | | | (1,942 | ) | | | — | | | | — | | | | 12,762 | |
| | | | | | | | | | | | | | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | 17,615 | | | | 876 | | | | (1,629 | ) | | | — | | | | (18,368 | ) |
Beginning cash and cash equivalents | | | 33,352 | | | | (2,716 | ) | | | 9,743 | | | | — | | | | 40,379 | |
| | | | | | | | | | | | | | | | | | | | |
Ending cash and cash equivalents | | $ | 15,737 | | | $ | (1,840 | ) | | $ | 8,114 | | | $ | — | | | $ | 22,011 | |
| | | | | | | | | | | | | | | | | | | | |
| |
| | | Year Ended December 31, 2009 | |
| | | Parent | | | Guarantor
Subsidiaries | | | Non-Guarantor
Subsidiaries | | | Eliminations | | | Consolidated | |
Cash flows from operating activities: | | $ | 26,598 | | | $ | 91,432 | | | $ | 5,283 | | | $ | — | | | $ | 123,313 | |
| | | | | | | | | | | | | | | | | | | | |
Cash flows from investing activities: | | | | | | | | | | | | | | | | | | | | |
Purchases of property and equipment | | | (404 | ) | | | (106,628 | ) | | | (7,680 | ) | | | — | | | | (114,712 | ) |
Proceeds from sale of property and equipment | | | — | | | | 694 | | | | 73 | | | | — | | | | 767 | |
Proceeds from insurance recoveries | | | — | | | | 36 | | | | — | | | | — | | | | 36 | |
| | | | | | | | | | | | | | | | | | | | |
| | | (404 | ) | | | (105,898 | ) | | | (7,607 | ) | | | — | | | | (113,909 | ) |
| | | | | | | | | | | | | | | | | | | | |
Cash flows from financing activities: | | | | | | | | | | | | | | | | | | | | |
Debt repayments | | | (15,152 | ) | | | (2,146 | ) | | | — | | | | — | | | | (17,298 | ) |
Debt issuance costs | | | (2,560 | ) | | | — | | | | — | | | | — | | | | (2,560 | ) |
Proceeds from common stock, net of offering costs of $454 | | | 24,043 | | | | — | | | | — | | | | — | | | | 24,043 | |
Purchase of treasury stock | | | (31 | ) | | | — | | | | — | | | | — | | | | (31 | ) |
| | | | | | | | | | | | | | | | | | | | |
| | | 6,300 | | | | (2,146 | ) | | | — | | | | — | | | | 4,154 | |
| | | | | | | | | | | | | | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | 32,494 | | | | (16,612 | ) | | | (2,324 | ) | | | — | | | | 13,558 | |
Beginning cash and cash equivalents | | | 858 | | | | 13,896 | | | | 12,067 | | | | — | | | | 26,821 | |
| | | | | | | | | | | | | | | | | | | | |
Ending cash and cash equivalents | | $ | 33,352 | | | $ | (2,716 | ) | | $ | 9,743 | | | $ | — | | | $ | 40,379 | |
| | | | | | | | | | | | | | | | | | | | |
| |
| | | Year Ended December 31, 2008 | |
| | | Parent | | | Guarantor
Subsidiaries | | | Non-Guarantor
Subsidiaries | | | Eliminations | | | Consolidated | |
Cash flows from operating activities: | | $ | 98,637 | | | $ | 71,444 | | | $ | 16,554 | | | $ | — | | | $ | 186,635 | |
| | | | | | | | | | | | | | | | | | | | |
Cash flows from investing activities: | | | | | | | | | | | | | | | | | | | | |
Acquisition of production services business of WEDGE | | | (313,621 | ) | | | — | | | | — | | | | — | | | | (313,621 | ) |
Acquisition of production services business of Competition | | | (26,772 | ) | | | — | | | | — | | | | — | | | | (26,772 | ) |
Acquisition of other production services businesses | | | (9,301 | ) | | | — | | | | — | | | | — | | | | (9,301 | ) |
Purchases of property and equipment | | | (1,831 | ) | | | (133,598 | ) | | | (12,026 | ) | | | — | | | | (147,455 | ) |
Purchase of auction rate securities, net | | | (15,900 | ) | | | — | | | | — | | | | — | | | | (15,900 | ) |
Proceeds from sale of property and equipment | | | — | | | | 4,008 | | | | — | | | | — | | | | 4,008 | |
Proceeds from insurance recoveries | | | — | | | | 3,426 | | | | — | | | | — | | | | 3,426 | |
| | | | | | | | | | | | | | | | | | | | |
| | | (367,425 | ) | | | (126,164 | ) | | | (12,026 | ) | | | — | | | | (505,615 | ) |
| | | | | | | | | | | | | | | | | | | | |
Cash flows from financing activities: | | | | | | | | | | | | | | | | | | | | |
Debt repayments | | | (87,305 | ) | | | (462 | ) | | | — | | | | — | | | | (87,767 | ) |
Proceeds from issuance of debt | | | 359,400 | | | | — | | | | — | | | | — | | | | 359,400 | |
Debt issuance costs | | | (3,319 | ) | | | — | | | | — | | | | — | | | | (3,319 | ) |
Proceeds from exercise of options | | | 784 | | | | — | | | | — | | | | — | | | | 784 | |
| | | | | | | | | | | | | | | | | | | | |
| | | 269,560 | | | | (462 | ) | | | — | | | | — | | | | 269,098 | |
| | | | | | | | | | | | | | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | 772 | | | | (55,182 | ) | | | 4,528 | | | | — | | | | (49,882 | ) |
Beginning cash and cash equivalents | | | 86 | | | | 69,078 | | | | 7,539 | | | | — | | | | 76,703 | |
| | | | | | | | | | | | | | | | | | | | |
Ending cash and cash equivalents | | $ | 858 | | | $ | 13,896 | | | $ | 12,067 | | | $ | — | | | $ | 26,821 | |
| | | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | |
| | Year ended December 31, 2013 |
| | Parent | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | Consolidated |
| Cash flows from operating activities | $ | 31,908 |
| | $ | 142,225 |
| | $ | 447 |
| | $ | 174,580 |
|
| Cash flows from investing activities: | | | | | | | |
| Purchases of property and equipment | (2,649 | ) | | (151,363 | ) | | (11,344 | ) | | (165,356 | ) |
| Proceeds from sale of property and equipment | 8 |
| | 12,510 |
| | 1,318 |
| | 13,836 |
|
| Proceeds from insurance recoveries | — |
| | 844 |
| | — |
| | 844 |
|
| | (2,641 | ) | | (138,009 | ) | | (10,026 | ) | | (150,676 | ) |
| Cash flows from financing activities: | | | | | | | |
| Debt repayments | (60,000 | ) | | (874 | ) | | — |
| | (60,874 | ) |
| Proceeds from issuance of debt | 40,000 |
| | — |
| | — |
| | 40,000 |
|
| Debt issuance costs | (13 | ) | | — |
| | — |
| | (13 | ) |
| Proceeds from exercise of options | 1,266 |
| | — |
| | — |
| | 1,266 |
|
| Purchase of treasury stock | (631 | ) | | — |
| | — |
| | (631 | ) |
| | (19,378 | ) | | (874 | ) | | — |
| | (20,252 | ) |
| Net increase (decrease) in cash and cash equivalents | 9,889 |
| | 3,342 |
| | (9,579 | ) | | 3,652 |
|
| Beginning cash and cash equivalents | 18,479 |
| | (5,401 | ) | | 10,655 |
| | 23,733 |
|
| Ending cash and cash equivalents | $ | 28,368 |
| | $ | (2,059 | ) | | $ | 1,076 |
| | $ | 27,385 |
|
| | | | | | | | |
| | Year ended December 31, 2012 |
| | Parent | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | Consolidated |
| Cash flows from operating activities | $ | (171,541 | ) | | $ | 338,418 |
| | $ | 32,489 |
| | $ | 199,366 |
|
| Cash flows from investing activities: | | | | | | | |
| Purchases of property and equipment | (2,187 | ) | | (332,082 | ) | | (30,055 | ) | | (364,324 | ) |
| Proceeds from sale of property and equipment | — |
| | 2,998 |
| | 95 |
| | 3,093 |
|
| | (2,187 | ) | | (329,084 | ) | | (29,960 | ) | | (361,231 | ) |
| Cash flows from financing activities: | | | | | | | |
| Debt repayments | — |
| | (856 | ) | | (18 | ) | | (874 | ) |
| Proceeds from issuance of debt | 100,000 |
| | — |
| | — |
| | 100,000 |
|
| Debt issuance costs | (58 | ) | | — |
| | — |
| | (58 | ) |
| Proceeds from exercise of options | 693 |
| | — |
| | — |
| | 693 |
|
| Purchase of treasury stock | (360 | ) | | — |
| | — |
| | (360 | ) |
| | 100,275 |
| | (856 | ) | | (18 | ) | | 99,401 |
|
| Net increase (decrease) in cash and cash equivalents | (73,453 | ) | | 8,478 |
| | 2,511 |
| | (62,464 | ) |
| Beginning cash and cash equivalents | 91,932 |
| | (13,879 | ) | | 8,144 |
| | 86,197 |
|
| Ending cash and cash equivalents | $ | 18,479 |
| | $ | (5,401 | ) | | $ | 10,655 |
| | $ | 23,733 |
|
| | |
| | Year ended December 31, 2011 |
| | Parent | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | Consolidated |
| Cash flows from operating activities | $ | (164,032 | ) | | $ | 300,198 |
| | $ | 8,713 |
| | $ | 144,879 |
|
| Cash flows from investing activities: | | | | | | | |
| Acquisition of production services business of Go-Coil | — |
| | (109,035 | ) | | — |
| | (109,035 | ) |
| Acquisition of other production services businesses | — |
| | (6,502 | ) | | — |
| | (6,502 | ) |
| Purchases of property and equipment | (485 | ) | | (200,887 | ) | | (8,694 | ) | | (210,066 | ) |
| Proceeds from sale of property and equipment | 7 |
| | 5,532 |
| | 11 |
| | 5,550 |
|
| Proceeds from sale of auction rate securities | 12,569 |
| | — |
| | — |
| | 12,569 |
|
| | 12,091 |
| | (310,892 | ) | | (8,683 | ) | | (307,484 | ) |
| Cash flows from financing activities: | | | | | | | |
| Debt repayments | (111,813 | ) | | (1,345 | ) | | — |
| | (113,158 | ) |
| Proceeds from issuance of debt | 250,750 |
| | — |
| | — |
| | 250,750 |
|
| Debt issuance costs | (7,285 | ) | | — |
| | — |
| | (7,285 | ) |
| Proceeds from exercise of options | 2,884 |
| | — |
| | — |
| | 2,884 |
|
| Proceeds from common stock, net of offering costs of $5,707 | 94,343 |
| | — |
| | — |
| | 94,343 |
|
| Purchase of treasury stock | (743 | ) | | — |
| | — |
| | (743 | ) |
| | 228,136 |
| | (1,345 | ) | | — |
| | 226,791 |
|
| Net increase (decrease) in cash and cash equivalents | 76,195 |
| | (12,039 | ) | | 30 |
| | 64,186 |
|
| Beginning cash and cash equivalents | 15,737 |
| | (1,840 | ) | | 8,114 |
| | 22,011 |
|
| Ending cash and cash equivalents | $ | 91,932 |
| | $ | (13,879 | ) | | $ | 8,144 |
| | $ | 86,197 |
|
| |
Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure |
| |
| Item 9A. | Controls and Procedures |
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2010,2013, to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and (2) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting that occurred during the three months ended December 31, 20102013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Management’s
Annual Report on Internal Control Over Financial Reporting
The management of Pioneer
Drilling CompanyEnergy Services Corp. is responsible for establishing and maintaining adequate internal control over financial reporting. Pioneer
Drilling Company'sEnergy Services Corp.'s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of Pioneer
Drilling CompanyEnergy Services Corp. are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Pioneer Drilling Company’sEnergy Services Corp.’s management assessed the effectiveness of Pioneer Drilling Company’sEnergy Services Corp.’s internal control over financial reporting as of December 31, 2010.2013. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.Framework (1992). Based on our assessment we have concluded that, as of December 31, 2010,2013, Pioneer Drilling Company’sEnergy Services Corp.’s internal control over financial reporting was effective based on those criteria. KPMG LLP, the independent registered public accounting firm that audited the consolidated financial statements of Pioneer Drilling CompanyEnergy Services Corp. included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of Pioneer Drilling Company’sEnergy Services Corp.’s internal control over financial reporting as of December 31, 2010.2013. This report appears on page 62.is included in Item 8, Financial Statements and Supplementary Data. | |
| Item 9B. | Other Information |
Not
applicable.Applicable.
In Items 10, 11, 12, 13 and 14 below, we are incorporating by reference the information we refer to in those Items from the definitive proxy statement for our 20112014 Annual Meeting of Shareholders. We intend to file that definitive proxy statement with the SEC on or about April 8, 2011.9, 2014.
| |
Item 10. | Directors, Executive Officers and Corporate Governance |
Please see the information appearing under the headings “Proposal 1—Election of Directors,” “Executive Officers,” “Information Concerning Meetings and Committees of the Board of Directors,” “Code of Business Conduct and Ethics”Ethics and Corporate Governance Guidelines” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the definitive proxy statement for our 20112014 Annual Meeting of Shareholders for the information this Item 10 requires. | |
Item 11. | Executive Compensation |
Please see the information appearing under the headings “Compensation Discussion and Analysis,” “Compensation of Directors,“Director Compensation,” “Compensation of Executive Officers,“Executive Compensation,” “Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report”“Report of the Compensation Committee” in the definitive proxy statement for our 20112014 Annual Meeting of Shareholders for the information this Item 11 requires. | |
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters |
Please see the information appearing under the headings “Equity Compensation Plan Information” and “Security Ownership of Certain Beneficial Owners and Management” in the definitive proxy statement for our 20112014 Annual Meeting of Shareholders for the information this Item 12 requires. | |
Item 13. | Certain Relationships and Related Transactions, and Director Independence |
Please see the information appearing under the headings “Proposal 1—Election of Directors” and “Certain Relationships and Related Transactions” in the definitive proxy statement for our 20112014 Annual Meeting of Shareholders for the information this Item 13 requires. | |
Item 14. | Principal Accountant Fees and Services |
Please see the information appearing under the heading “Proposal 2—3—Ratification of the Appointment of our Independent Auditors”Registered Public Accounting Firm” in the definitive proxy statement for our 20112014 Annual Meeting of Shareholders for the information this Item 14 requires.
| |
Item 15. | Exhibits and Financial Statement Schedules |
(1) Financial Statements.
See Index to Consolidated Financial Statements on page 61.included in Item 8,
Financial Statements and Supplementary Data. (2) Financial Statement Schedules
No financial statement schedules are submitted because either they are inapplicable or because the required information is included in the consolidated financial statements or notes thereto.
(3) Exhibits.
The following exhibits are filed as part of this report:
| | | | |
Exhibit
Number
| | | | Description
|
2.1* | | - | | Securities Purchase Agreement, dated January 31, 2008, by and among Pioneer Drilling Company, WEDGE Group Incorporated, WEDGE Energy Holdings, L.L.C., WEDGE Oil & Gas Services, L.L.C., Timothy Daley, John Patterson and Patrick Grissom (Form 8-K dated February 1, 2008 (File No. 1-8182, Exhibit 2.1)).
|
| | |
2.2*Exhibit
Number | | -Description |
| | Letter Agreement, dated February 29, 2008, amending the Securities Purchase Agreement, dated January 31, 2008, by and among Pioneer Drilling Company, WEDGE Group Incorporated, WEDGE Energy Holdings, L.L.C., WEDGE Oil & Gas Services, L.L.C., Timothy Daley, John Patterson and Patrick Grissom (Form 8-K dated March 3, 2008 (File No. 1-8182, Exhibit 2.1)).
|
| | |
| 3.1* | | - | | Restated Articles of Incorporation of Pioneer Drilling CompanyEnergy Services Corp. (Form 10-K for the year ended December 31, 20088-K dated July 30, 2012 (File No. 1-8182, Exhibit 3.1)). |
| | |
3.2* | | |
| 3.2* | - | | Amended and Restated Bylaws of Pioneer Drilling CompanyEnergy Services Corp. (Form 8-K dated December 15, 2008July 30, 2012 (File No. 1-8182, Exhibit 3.1)3.2)). |
| | |
4.1* | | |
| 4.1* | - | | Form of Certificate representing Common Stock of Pioneer Drilling CompanyEnergy Services Corp. (Form S-8 filed November 18, 2003 (Reg.10-Q dated August 7, 2012 (File No. 333-110569,1-8182, Exhibit 4.3)4.1)). |
| | |
4.2* | | |
| 4.2* | - | | Indenture, dated March 11, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (Form 8-K dated March 12, 2010 (File No. 1-8182, Exhibit 4.1)). |
| | |
4.3* | | |
| 4.3* | - | | Registration Rights Agreement, dated March 11, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated March 12, 2010 (File No. 1-8182, Exhibit 4.2)). |
| | |
| 4.4* | - | First Supplemental Indenture, dated November 21, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (Form 8-K dated November 21, 2011 (File No. 1-8182, Exhibit 4.2)). |
| | |
| 4.5* | - | Registration Rights Agreement, dated November 21, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated November 21, 2011 (File No. 1-8182, Exhibit 4.3)). |
| | |
| 4.6* | - | Second Supplemental Indenture, dated October 1, 2012, among Pioneer Coiled Tubing Services, LLC, Pioneer Energy Services Corp., the other subsidiary guarantors and Wells Fargo Bank, National Association, as trustee (Form 10-Q dated November 1, 2012 (File No. 1-8182, Exhibit 4.6)).
|
| | |
| 10.1* | | - | | Purchase Agreement, dated March 4, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated March 5, 2010 (File No. 1-8182, Exhibit 10.1)). |
| | |
| 10.2* | - | Purchase Agreement, dated November 15, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated November 16, 2011 (File No. 1-8182, Exhibit 10.1)).
|
| | |
| 10.3*+ | - | | Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.1)). |
| | |
10.3+* | | |
| 10.4+* | - | | Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.2)). |
| | |
10.4+* | | |
| 10.5+* | - | | Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Restricted Stock Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.3)). |
|
| | |
10.5+* | | |
| 10.6+* | - | | Pioneer Drilling Company 2007 Incentive Plan Form of Restricted Stock Unit Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.4)). |
| | | | |
Exhibit
Number
| | | | Description
|
10.6+* | | - | | Pioneer Drilling Services, Ltd. Annual Incentive Compensation Plan dated August 5, 2005 (Form 8-K dated August 5, 2005 (File No. 1-8182, Exhibit 10.1)).
|
| | |
| 10.7+* | - | | | Pioneer Drilling Company Amended and Restated Key Executive Severance Plan dated December 10, 2007 (Form 10-Q for the quarter ended March 31,dated August 5, 2008 (File No. 1-8182, Exhibit 10.4)). |
| | |
| 10.8+* | | - | | Pioneer Drilling Company’s 1995 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31,dated June 22, 2001 (File No. 1-8182, Exhibit 10.5)). |
| | |
| 10.9+* | | - | | Pioneer Drilling Company’s 1999 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31,dated June 22, 2001 (File No. 1-8182, Exhibit 10.7)). |
| | |
| 10.10+* | | - | | Pioneer Drilling Company 2003 Stock Plan (Form S-8 fileddated November 18, 2003 (File No. 333-110569, Exhibit 4.4)). |
| | |
| 10.11+* | | - | | Pioneer Drilling Company Amended and Restated Pioneer Drilling Company 2007 Incentive Plan adopted May 15, 2009 (Definitive Proxy Statement on Schedule 14A, filed April 10, 2009(Form 10-Q dated November 3, 2011 (File No. 1-8182, Appendix A)Exhibit 10.1)). |
| | |
| 10.12+* | | - | | Pioneer Drilling Company 2007 Incentive Plan Form of Stock Option Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.1)). |
| | |
| 10.13+* | | - | | Pioneer Drilling Company 2007 Incentive Plan Form of Employee Restricted Stock Award Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.2)). |
| | |
| 10.14+* | | - | | Pioneer Drilling Company 2007 Incentive Plan Form of Non-Employee Director Restricted Stock Award Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.3)). |
| | |
| 10.15+* | | - | | Pioneer Drilling Company Form of Indemnification Agreement (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.1)). |
| | |
| 10.16+* | | - | | Pioneer Drilling Company Employee Relocation Policy Executive Officers – Package A (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.3)). |
| | |
| 10.17* | | - | | Credit Agreement, dated February 29, 2008, among Pioneer Drilling Company, as Borrower,Amended and Wells Fargo Bank, N.A., as administrative agent, issuing lender, swing line lender and co-lead arranger, Fortis Bank SA/NV, New York Branch, as co-lead arranger, and each of the other parties listed therein (Form 8-K dated March 3, 2008 (File No. 1-8182, Exhibit 10.1)).
|
| | |
10.18* | | - | | First Amendment toRestated Credit Agreement, dated as of October 5, 2009,June 30, 2011 among Pioneer Drilling Company, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent, issuing lender and swing line lender (Form 8-K dated October 6, 2009July 5, 2011 (File No. 1-8182, Exhibit 10.1))
.
|
| | |
10.19* | | - | | Waiver Agreement, dated as of June 9, 2008, among Pioneer Drilling Company, the guarantors party thereto, Wells Fargo Bank, N.A., as administrative agent, issuing lender and swing line lender, and each of the other financial institutions party thereto (Form 8-K dated June 11, 2008 (File No. 1-8182, Exhibit 10.1)).
|
| | |
10.20* | 10.18+* | - | | Second Amendment to Credit Agreement, dated as of February 23, 2010, among Pioneer Drilling Company, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent, issuing lender and swing line lender (Form 8-K dated February 23, 2010 (File No. 1-8182, Exhibit 10.1)).
|
| | |
10.21+* | | - | | Employment Letter, effective March 1, 2008, from Pioneer Drilling Company to Joseph B. Eustace (Form 8-K dated March 5, 2008 (File No. 1-8182, Exhibit 10.1)). |
| | |
10.22+* | | |
| 10.19+* | - | | Confidentiality and Non-Competition Agreement, dated February 29, 2008, by and between Pioneer Drilling Company, Pioneer Production Services, Inc. and Joe Eustace (Form 8-K dated March 5, 2008 (File No. 1-8182, Exhibit 10.2)). |
| | | | |
Exhibit
Number
| | | | Description
|
10.24+10.20+* | | - | | Employment Letter, Agreement, effective January 7, 2009, from Pioneer Drilling Company to Lorne E. Phillips (Form 8-K dated January 14, 2009 (File No. 1-8182, Exhibit 10.1)). |
| | |
21.1 | | |
| 10.21+* | - | Pioneer Energy Services Corp. Nonqualified Retirement Savings and Investment Plan (Form 8-K dated January 30, 2013 (File No. 1-8182, Exhibit 10.1)). |
| | |
| 10.22+* | - | Amended and Restated Pioneer Energy Services Corp. 2007 Incentive Plan (Appendix A of definitive proxy statement on Schedule 14A dated April 12, 2013 (File No. 1-8182, Exhibit 10.1)). |
| | |
| 12.1** | - | Computation of ratio of earnings to fixed charges. |
| | |
| 21.1** | - | Subsidiaries of Pioneer Drilling Company.Energy Services Corp. |
| | |
23.1 | | |
| 23.1** | - | | Consent of Independent Registered Public Accounting Firm. |
| | |
31.1 | | |
| 31.1** | - | | Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934. |
| | |
31.2 | | |
| 31.2** | - | | Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934. |
| | |
|
| | |
32.1 | 32.1# | - | | Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code). 2002. |
| | |
32.2 | | |
| 32.2# | - | | Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a)2002. |
| | |
| 101** | - | The following financial statements from Pioneer Energy Services Corp.’s Form 10-K for the year ended December 31, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Shareholders' Equity, (iv) Consolidated Statements of Cash Flows, and (b) of Section 1350, Chapter 63 of Title 18, United States Code).(v) Notes to Consolidated Financial Statements. |
_______________
| |
| * | Incorporated by reference to the filing indicated. |
| |
| + | Management contract or compensatory plan or arrangement. |
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
| | |
| | | PIONEER DRILLING COMPANY ENERGY SERVICES CORP. |
| |
February 17, 2011
| | BY: /S/ WM. STACY LOCKE
|
| February 13, 2014 | | /S/ WM. STACY LOCKE |
| | Chief Executive Officer and President |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
|
| | | | |
Signature
| | Title
| | Date
|
Signature | | Title | | Date |
/S/ DEAN A. BURKHARDTDean A. Burkhardt
| | Chairman | | February 17, 201113, 2014 |
| | |
/S/ WM. STACY LOCKE
Wm. Stacy Locke
Dean A. Burkhardt | | | | |
/S/ WM. STACY LOCKE | | President, Chief Executive Officer and Director (Principal (Principal Executive Officer) | | February 17, 201113, 2014 |
| Wm. Stacy Locke | | | | |
/S/ LORNE E. E. PHILLIPSLorne E. Phillips
| | Executive Vice President and Chief Financial Officer (Principal Accounting Officer) | | February 17, 201113, 2014 |
| Lorne E. Phillips | | | | |
/S/ C. JOHN THOMPSONC. John Thompson
| | Director | | February 17, 201113, 2014 |
| C. John Thompson | | | | |
/S/ JOHN MICHAEL RAUHJohn Michael Rauh
| | Director | | February 17, 201113, 2014 |
| John Michael Rauh | | | | |
/S/ SCOTT D. URBANScott D. Urban
| | Director | | February 17, 2011 |
| | | | 13, 2014 |
Exhibit
Number
Scott D. Urban | | | | Description
|
Index to Exhibits
2.1* | | - | | Securities Purchase Agreement, dated January 31, 2008, by and among Pioneer Drilling Company, WEDGE Group Incorporated, WEDGE Energy Holdings, L.L.C., WEDGE Oil & Gas Services, L.L.C., Timothy Daley, John Patterson and Patrick Grissom (Form 8-K dated February 1, 2008 (File No. 1-8182, Exhibit 2.1)).
|
| | |
2.2*Exhibit
Number | | -Description |
| | Letter Agreement, dated February 29, 2008, amending the Securities Purchase Agreement, dated January 31, 2008, by and among Pioneer Drilling Company, WEDGE Group Incorporated, WEDGE Energy Holdings, L.L.C., WEDGE Oil & Gas Services, L.L.C., Timothy Daley, John Patterson and Patrick Grissom (Form 8-K dated March 3, 2008 (File No. 1-8182, Exhibit 2.1)).
|
| | |
| 3.1* | | - | | Restated Articles of Incorporation of Pioneer Drilling CompanyEnergy Services Corp. (Form 10-K for the year ended December 31, 20088-K dated July 30, 2012 (File No. 1-8182, Exhibit 3.1)). |
| | |
3.2* | | |
| 3.2* | - | | Amended and Restated Bylaws of Pioneer Drilling CompanyEnergy Services Corp. (Form 8-K dated December 15, 2008July 30, 2012 (File No. 1-8182, Exhibit 3.1)3.2)). |
| | |
4.1* | | |
| 4.1* | - | | Form of Certificate representing Common Stock of Pioneer Drilling CompanyEnergy Services Corp. (Form S-8 filed November 18, 2003 (Reg.10-Q dated August 7, 2012 (File No. 333-110569,1-8182, Exhibit 4.3)4.1)). |
| | |
4.2* | | |
| 4.2* | - | | Indenture, dated March 11, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (Form 8-K dated March 12, 2010 (File No. 1-8182, Exhibit 4.1)). |
| | |
4.3* | | |
| 4.3* | - | | Registration Rights Agreement, dated March 11, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated March 12, 2010 (File No. 1-8182, Exhibit 4.2)). |
| | |
| 4.4* | - | First Supplemental Indenture, dated November 21, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (Form 8-K dated November 21, 2011 (File No. 1-8182, Exhibit 4.2)). |
| | |
| 4.5* | - | Registration Rights Agreement, dated November 21, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated November 21, 2011 (File No. 1-8182, Exhibit 4.3)). |
| | |
| 4.6* | - | Second Supplemental Indenture, dated October 1, 2012, among Pioneer Coiled Tubing Services, LLC, Pioneer Energy Services Corp., the other subsidiary guarantors and Wells Fargo Bank, National Association, as trustee (Form 10-Q dated November 1, 2012 (File No. 1-8182, Exhibit 4.6)).
|
| | |
| 10.1* | | - | | Purchase Agreement, dated March 4, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated March 5, 2010 (File No. 1-8182, Exhibit 10.1)). |
| | |
| 10.2* | - | Purchase Agreement, dated November 15, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated November 16, 2011 (File No. 1-8182, Exhibit 10.1)).
|
| | |
| 10.3*+ | - | | Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.1)). |
| | |
10.3+* | | |
| 10.4+* | - | | Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.2)). |
| | |
10.4+* | | |
| 10.5+* | - | | Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Restricted Stock Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.3)). |
| | |
10.5+* | | |
| 10.6+* | - | | Pioneer Drilling Company 2007 Incentive Plan Form of Restricted Stock Unit Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.4)). |
| | |
10.6+* | | - | | Pioneer Drilling Services, Ltd. Annual Incentive Compensation Plan dated August 5, 2005 (Form 8-K dated August 5, 2005 (File No. 1-8182, Exhibit 10.1)).
|
| | |
| 10.7+* | - | | | Pioneer Drilling Company Amended and Restated Key Executive Severance Plan dated December 10, 2007 (Form 10-Q for the quarter ended March 31,dated August 5, 2008 (File No. 1-8182, Exhibit 10.4)). |
| | |
| 10.8+* | | - | | Pioneer Drilling Company’s 1995 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31,dated June 22, 2001 (File No. 1-8182, Exhibit 10.5)). |
| | |
| 10.9+* | | - | | Pioneer Drilling Company’s 1999 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31,dated June 22, 2001 (File No. 1-8182, Exhibit 10.7)). |
| | | | |
Exhibit
Number
| | | | Description
|
| 10.10+* | | - | | Pioneer Drilling Company 2003 Stock Plan (Form S-8 fileddated November 18, 2003 (File No. 333-110569, Exhibit 4.4)). |
| | |
|
| | |
| 10.11+* | | - | | Pioneer Drilling Company Amended and Restated Pioneer Drilling Company 2007 Incentive Plan adopted May 15, 2009 (Definitive Proxy Statement on Schedule 14A, filed April 10, 2009(Form 10-Q dated November 3, 2011 (File No. 1-8182, Appendix A)Exhibit 10.1)). |
| | |
| 10.12+* | | - | | Pioneer Drilling Company 2007 Incentive Plan Form of Stock Option Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.1)). |
| | |
| 10.13+* | | - | | Pioneer Drilling Company 2007 Incentive Plan Form of Employee Restricted Stock Award Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.2)). |
| | |
| 10.14+* | | - | | Pioneer Drilling Company 2007 Incentive Plan Form of Non-Employee Director Restricted Stock Award Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.3)). |
| | |
| 10.15+* | | - | | Pioneer Drilling Company Form of Indemnification Agreement (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.1)). |
| | |
| 10.16+* | | - | | Pioneer Drilling Company Employee Relocation Policy Executive Officers – Package A (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.3)). |
| | |
| 10.17* | | - | | Credit Agreement, dated February 29, 2008, among Pioneer Drilling Company, as Borrower,Amended and Wells Fargo Bank, N.A., as administrative agent, issuing lender, swing line lender and co-lead arranger, Fortis Bank SA/NV, New York Branch, as co-lead arranger, and each of the other parties listed therein (Form 8-K dated March 3, 2008 (File No. 1-8182, Exhibit 10.1)).
|
| | |
10.18* | | - | | First Amendment toRestated Credit Agreement, dated as of October 5, 2009,June 30, 2011 among Pioneer Drilling Company, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent, issuing lender and swing line lender (Form 8-K dated October 6, 2009July 5, 2011 (File No. 1-8182, Exhibit 10.1))
.
|
| | |
10.19* | | - | | Waiver Agreement, dated as of June 9, 2008, among Pioneer Drilling Company, the guarantors party thereto, Wells Fargo Bank, N.A., as administrative agent, issuing lender and swing line lender, and each of the other financial institutions party thereto (Form 8-K dated June 11, 2008 (File No. 1-8182, Exhibit 10.1)).
|
| | |
10.20* | 10.18+* | - | | Second Amendment to Credit Agreement, dated as of February 23, 2010, among Pioneer Drilling Company, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent, issuing lender and swing line lender (Form 8-K dated February 23, 2010 (File No. 1-8182, Exhibit 10.1)).
|
| | |
10.21+* | | - | | Employment Letter, effective March 1, 2008, from Pioneer Drilling Company to Joseph B. Eustace (Form 8-K dated March 5, 2008 (File No. 1-8182, Exhibit 10.1)). |
| | |
10.22+* | | |
| 10.19+* | - | | Confidentiality and Non-Competition Agreement, dated February 29, 2008, by and between Pioneer Drilling Company, Pioneer Production Services, Inc. and Joe Eustace (Form 8-K dated March 5, 2008 (File No. 1-8182, Exhibit 10.2)). |
| | |
10.24+* | | |
| 10.20+* | - | | Employment Letter, Agreement, effective January 7, 2009, from Pioneer Drilling Company to Lorne E. Phillips (Form 8-K dated January 14, 2009 (File No. 1-8182, Exhibit 10.1)). |
| | |
21.1 | | |
| 10.21+* | - | Pioneer Energy Services Corp. Nonqualified Retirement Savings and Investment Plan (Form 8-K dated January 30, 2013 (File No. 1-8182, Exhibit 10.1)). |
| | |
| 10.22+* | - | Amended and Restated Pioneer Energy Services Corp. 2007 Incentive Plan (Appendix A of definitive proxy statement on Schedule 14A dated April 12, 2013 (File No. 1-8182, Exhibit 10.1)). |
| | |
| 12.1** | - | Computation of ratio of earnings to fixed charges. |
| | |
| 21.1** | - | Subsidiaries of Pioneer Drilling Company.Energy Services Corp. |
| | |
23.1 | | |
| 23.1** | - | | Consent of Independent Registered Public Accounting Firm. |
| | |
31.1 | | |
| 31.1** | - | | Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934. |
| | | | |
Exhibit
Number
| | | | Description
|
31.2 | 31.2** | - | | Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934. |
| | |
32.1 | | |
| 32.1# | - | | Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code). 2002. |
| | |
32.2 | | |
| 32.2# | - | | Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a)2002. |
| | |
| 101** | - | The following financial statements from Pioneer Energy Services Corp.’s Form 10-K for the year ended December 31, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Shareholders' Equity, (iv) Consolidated Statements of Cash Flows, and (b) of Section 1350, Chapter 63 of Title 18, United States Code).(v) Notes to Consolidated Financial Statements. |
* | Incorporated by reference to the filing indicated.
|
+ | Management contract or compensatory plan or arrangement.
|
108
* Incorporated by reference to the filing indicated.
** Filed herewith.
# Furnished herewith.
+ Management contract or compensatory plan or arrangement.
